ML083010454
| ML083010454 | |
| Person / Time | |
|---|---|
| Site: | Perry  |
| Issue date: | 10/27/2008 |
| From: | Jamnes Cameron NRC/RGN-III/DRP/RPB6 |
| To: | Bezilla M FirstEnergy Nuclear Operating Co |
| References | |
| EA-07-199, FOIA/PA-2010-0209 IR-08-004 | |
| Download: ML083010454 (53) | |
See also: IR 05000440/2008004
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION III
2443 WARRENVILLE ROAD, SUITE 210
LISLE, IL 60532-4352
October 27, 2008
Mr. Mark Bezilla
Site Vice President
FirstEnergy Nuclear Operating Company
Perry Nuclear Power Plant
P. O. Box 97, 10 Center Road, A-PY-290
Perry, OH 44081-0097
SUBJECT:
PERRY NUCLEAR POWER PLANT NRC INTEGRATED INSPECTION
REPORT 05000440/2008004
Dear Mr. Bezilla:
On September 30, 2008, the U.S. Nuclear Regulatory Commission (NRC) completed an
inspection at your Perry Nuclear Power Plant. The enclosed report documents the inspection
findings which were discussed on October 14, 2008, with you and members of your staff.
The inspection examined activities conducted under your license as they relate to safety and
compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed
personnel.
Based on the results of this inspection, three NRC-identified findings and four self-revealed
findings of very low safety significance were identified (Green). Five of the seven findings
involved violations of NRC requirements. Additionally, three licensee-identified violations are
listed in Section 4OA7 of this report. However, because of the very low safety significance and
because the issues were entered into your corrective action program, the NRC is treating these
issues as Non-Cited Violations (NCVs) in accordance with Section VI.A.1 of the NRCs
If you contest the subject or severity of any NCV in this report, you should provide a response
within 30 days of the date of this inspection report, with the basis for your denial, to the U.S.
Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC
20555-0001; with copies to the Regional Administrator, U.S. Nuclear Regulatory Commission,
Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of
Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the
NRC Resident Inspectors Office at the Perry Nuclear Power Plant.
M. Bezilla
-2-
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its
enclosure will be available electronically for public inspection in the NRC Public Document
Room or from the Publicly Available Records (PARS) component of NRC's document system
(ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html
(the Public Electronic Reading Room).
Sincerely,
/RA/
Jamnes L. Cameron, Chief
Reactor Projects Branch 6
Docket No. 50-440
License No. NPF-58
Enclosure:
Inspection Report 05000440/2008004
w/Attachment: Supplemental Information
cc w/encl:
J. Hagan, President and Chief Nuclear Officer - FENOC
J. Lash, Senior Vice President of Operations and
Chief Operating Officer - FENOC
D. Pace, Senior Vice President, Fleet Engineering - FENOC
J. Rinckel, Vice President, Fleet Oversight - FENOC
P. Harden, Vice President, Nuclear Support
Director, Fleet Regulatory Affairs - FENOC
Manager, Fleet Licensing - FENOC
Manager, Site Regulatory Compliance - FENOC
D. Jenkins, Attorney, FirstEnergy Corp.
Public Utilities Commission of Ohio
C. OClaire, State Liaison Officer, Ohio Emergency Management Agency
R. Owen, Ohio Department of Health
M. Bezilla
-2-
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its
enclosure will be available electronically for public inspection in the NRC Public Document
Room or from the Publicly Available Records (PARS) component of NRC's document system
(ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html
(the Public Electronic Reading Room).
Sincerely,
/RA/
Jamnes L. Cameron, Chief
Reactor Projects Branch 6
Docket No. 50-440
License No. NPF-58
Enclosure:
Inspection Report 05000440/2008004
w/Attachment: Supplemental Information
cc w/encl:
J. Hagan, President and Chief Nuclear Officer - FENOC
J. Lash, Senior Vice President of Operations and
Chief Operating Officer - FENOC
D. Pace, Senior Vice President, Fleet Engineering - FENOC
J. Rinckel, Vice President, Fleet Oversight - FENOC
P. Harden, Vice President, Nuclear Support
Director, Fleet Regulatory Affairs - FENOC
Manager, Fleet Licensing - FENOC
Manager, Site Regulatory Compliance - FENOC
D. Jenkins, Attorney, FirstEnergy Corp.
Public Utilities Commission of Ohio
C. OClaire, State Liaison Officer, Ohio Emergency Management Agency
R. Owen, Ohio Department of Health
DOCUMENT NAME: G:\\PERRY\\PERR 2008 004.DOC
G Publicly Available
G Non-Publicly Available
G Sensitive
G Non-Sensitive
To receive a copy of this document, indicate in the concurrence box "C" = Copy without attach/encl "E" =
Copy with attach/encl "N" = No copy
OFFICE
RIII
RIII
RIII
RIII
NAME
JCameron:cms
DATE
10/27/08
OFFICIAL RECORD COPY
Letter to M. Bezilla from J. Cameron dated October 27, 2008
SUBJECT:
PERRY NUCLEAR POWER PLANT NRC INTEGRATED INSPECTION
REPORT 05000440/2008004
DISTRIBUTION:
RidsNrrPMPerry
RidsNrrDorlLpI3-2
RidsNrrDirsIrib Resource
Mark Satorius
Kenneth Obrien
Cynthia Pederson
DRPIII
DRSIII
Patricia Buckley
ROPreports@nrc.gov
Enclosure
U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket No:
50-440
License No:
Report No:
050000440/2008004
Licensee:
FirstEnergy Nuclear Operating Company (FENOC)
Facility:
Perry Nuclear Power Plant, Unit 1
Location:
Perry, Ohio
Dates:
July 1, 2008 through September 30, 2008
Inspectors:
M. Franke, Senior Resident Inspector
M. Wilk, Resident Inspector
T. Taylor, Reactor Engineer
J. Robbins, Reactor Engineer
D. Reeser, Operations Engineer
R. Murray, Reactor Engineer
M. Phalen, Health Physicist
R. Baker, Resident Inspector, Duane Arnold Energy Center
Observer:
E. Denison, Ohio Department of Health
Approved by:
Jamnes L. Cameron, Chief
Branch 6
Division of Reactor Projects
Enclosure
TABLE OF CONTENTS
SUMMARY OF FINDINGS .........................................................................................................1
REPORT DETAILS.....................................................................................................................5
Summary of Plant Status.........................................................................................................5
1.
REACTOR SAFETY.....................................................................................................5
1R01
Adverse Weather Protection (71111.01) ............................................................5
1R04
Equipment Alignment (71111.04).......................................................................6
1R05
Fire Protection (71111.05) .................................................................................7
1R06
Flood Protection Measures (71111.06) ............................................................11
1R11
Licensed Operator Requalification Program.....................................................11
1R12
Maintenance Effectiveness (71111.12) ............................................................12
1R13
Maintenance Risk Assessments and Emergent Work Control (71111.13)........13
1R15
Operability Evaluations (71111.15) ..................................................................16
1R19
Post-Maintenance Testing (71111.19) .............................................................18
1R22
Surveillance Testing (71111.22).......................................................................19
1EP6
Drill Evaluation (71114.06)...............................................................................21
2.
RADIATION SAFETY.................................................................................................21
2OS1
Access Control to Radiologically Significant Areas (71121.01) ........................21
4.
OTHER ACTIVITIES ..................................................................................................24
4OA1
Performance Indicator Verification (71151)......................................................24
4OA2
Identification and Resolution of Problems (71152)...........................................27
4OA3
Follow-up of Events and Notices of Enforcement Discretion (71153)...............31
4OA6
Meetings..........................................................................................................38
4OA7
Licensee-Identified Violations ..........................................................................38
SUPPLEMENTAL INFORMATION .............................................................................................1
KEY POINTS OF CONTACT ..................................................................................................1
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED .......................................................1
LIST OF DOCUMENTS REVIEWED ......................................................................................3
LIST OF ACRONYMS USED ..................................................................................................8
1
Enclosure
SUMMARY OF FINDINGS
IR 05000440/2008004; 07/01/2008 - 09/30/2008; Fire Protection; Operability Evaluations;
Maintenance Risk Assessments and Emergent Work Control; Identification and Resolution of
Problems; Event Follow-up.
The inspection was conducted by resident and regional inspectors. The report covers a
3-month period of resident inspection. The significance of most findings is indicated by their
color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609 Significance
Determination Process (SDP). Findings for which the SDP does not apply may be "Green," or
be assigned a severity level after NRC management review. The NRC's program for
overseeing the safe operation of commercial nuclear power reactors is described in
NUREG-1649, "Reactor Oversight Process," Revision 4, dated July 2006.
A.
Inspector-Identified and Self-Revealed Findings
Cornerstone: Initiating Event
Green. A finding of very low safety significance was self-revealed on July 30, 2008.
While performing inspection and dewatering of an underground vault area, plant workers
inadvertently dropped a man-hole cover into the vault. The 15-foot vault area contained
125 Volts direct current control power conduits that supplied fault protection circuitry for
switchyard breakers. The licensee entered the issue into their corrective action
program.
This finding was considered more than minor because it was related to maintenance risk
assessment and risk management issues. Specifically, the licensee failed to manage
risk for maintenance activities associated with the electrical switchyard that could
increase the likelihood of initiating events by causing a loss of offsite power. The finding
was determined through a SDP analysis to be of very low safety significance as no
mitigation equipment or functions were affected. This finding had a cross-cutting aspect
in the area of Human Performance as defined in IMC 0305 H.4(a), because the
organization failed to ensure the use of human error prevention techniques
commensurate with the risk of the assigned task. No violation of NRC requirements
occurred. (Section 4OA3.2)
Green. A finding of very low safety significance was self-revealed on June 28, 2008,
when high radiation alarms for all four main steam lines were received in the control
room during a plant power maneuver. Specifically, maintenance technicians failed to
adhere to procedures and manipulated a hydrogen water chemistry control system while
performing a surveillance test associated with the plant off-gas system. The off-gas
system surveillance test procedure did not address operation of the hydrogen water
chemistry control system and the technicians were not trained to operate the system.
As part of their immediate corrective actions, the licensee corrected the system lineup to
reduce radiation levels and entered the issue into their corrective action program.
This finding was considered more than minor because the manipulation of plant systems
that are different from those specified in the authorized work procedure would become a
more significant safety concern if left uncorrected. In this case, the finding led to an
unexpected increase in radiation levels in areas accessible to plant personnel and was
associated with the operating equipment lineup of the configuration control attribute of
2
Enclosure
the Initiating Events Cornerstone and adversely affected the cornerstone objective of
limiting the likelihood of events that upset plant stability. The finding was determined
through a SDP analysis to be of very low safety significance as no mitigation equipment
or functions were affected and no actual increase in personnel exposure occurred. This
finding has a cross-cutting aspect in the area of Human Performance as defined in
IMC 0305 H.4(b), because the organization failed to ensure that personnel do not
proceed with a task in the face of uncertainty. No violation of NRC requirements
occurred. (Section 4OA3.3)
Mitigating System
Green. The inspectors identified a finding of very low safety significance and an
associated NCV of 10 CFR 50.65(a)(4) for failure to assess and manage the risk
associated with maintenance activity affecting the low pressure core spray system.
Specifically, the licensee removed floor plugs in the auxiliary building and failed to
implement risk control measures to assure operability of low pressure core spray. As
part of their immediate corrective actions, the licensee personnel re-installed building
floor plugs and returned low pressure core spray to an operable status.
The finding was considered more than minor because the licensee failed to prescribe
significant compensatory measures for external conditions; and if the practice were left
uncorrected, the issue would become a more significant safety concern. The finding
was of very low safety significance because the incremental core damage frequency
associated with the activity was less than 1 X 10-6. This finding has a cross-cutting
aspect in the area of Human Performance as defined in IMC 0305 H.3(a), because the
organization failed to adequately plan work activities that are associated with risk.
(Section 1R13.1)
Green. The inspectors identified a finding of very low safety significance and a NCV of
10 CFR 50.65(a)(4) for failure to implement a procedurally-required risk management
activity for a safety system protected train. The licensee failed to provide required
management oversight of work on emergency closed cooling 'A' while the plant was in
Yellow Risk. The licensee entered the issue into their corrective action program.
The finding was considered more than minor because the licensee failed to effectively
manage significant compensatory measures for an elevated risk condition; and if the
practice were left uncorrected, the issue would become a more significant safety
concern. The finding was of very low safety significance, because the incremental core
damage frequency associated with the activity was less than 1 X 10-6. This finding has a
cross-cutting aspect in the area of Human Performance as defined by IMC 0305 H.3(a),
because the organization failed to adequately plan work activities that are associated
with risk. (Section 1R13.2)
Green. The inspectors identified a finding of very low safety significance and an
associated NCV of the Perry Nuclear Power Plant Operating License Condition C(6).
During a maintenance activity, licensee personnel degraded a fire barrier in a manner
that was contrary to the procedural requirements of the Perry Plant Fire Protection
Program. As part of their immediate corrective action, the licensee restored the fire
barrier and entered the issue into their corrective action program.
3
Enclosure
The inspectors determined that the performance deficiency was more than minor in
accordance with IMC 0612, Appendix B, Issue Disposition Screening, because the
finding was associated with protection against external factors attribute of the Mitigating
Systems Cornerstone and affected the cornerstone objective of ensuring the availability,
reliability, and capability of systems that respond to initiating events to prevent
undesirable consequences. Specifically, by the inappropriate use of fixed impairments
on the fire doors between the diesel fire pump room and the emergency service water
pumphouse, the licensee removed a fire barrier which could impact safety-related
equipment. The finding was determined to be of very low safety significance during a
Phase 2 SDP review. This finding has a cross-cutting aspect in the area of Human
Performance as defined by IMC 0305 H.4(a), because the licensee did not ensure that
appropriate human error prevention techniques were used. (Section 1R05)
Green. A finding of very low safety significance and associated NCV of 10 CFR Part 50,
Appendix B, Criterion V, Instructions, Procedures, and Drawings, was self-revealed on
August 4, 2008, when contract workers bored a hole into a safety-related structure in an
inappropriate location. The workers did not use documented instructions, procedures, or
drawings when performing the work. As part of their immediate corrective actions, the
licensee conducted worker training and entered the issue into their corrective action
program.
The finding was determined to be more than minor because the finding was associated
with the design control attribute of Mitigating Systems Cornerstone and affected the
cornerstone objective of ensuring the availability, reliability, and capability of systems
that respond to initiating events to prevent undesirable consequences. Specifically, the
licensee initiated work on a seismically qualified structure in the absence of an approved
work package and degraded the structure. The finding was determined to be of very low
safety significance because it did not result in safety system inoperability. This finding
had a cross-cutting aspect in the area of Human Performance as defined by
IMC 0305 H.4.(a), because the licensee failed to communicate human error prevention
techniques through a pre-job brief and personnel proceeded in the face of unexpected
circumstances. (Section 1R15)
Green. A self-revealed finding of very low safety significance and an associated NCV of
10 CFR Part 50 Appendix B, Criterion 5 , Procedures, was identified on June 1, 2008,
when a containment airlock door seal failed during routine operations. On
March 26, 2008, the licensee failed to implement airlock maintenance procedures
appropriate to the circumstances and this led to a failure of the containment upper
airlock outer door seal. As part of their corrective actions, the licensee (1) conducted
worker training; (2) planned to revise the airlock maintenance procedures to include
additional guidance; (3) planned to increase maintenance frequency for the airlocks; and
(4) planned to reintroduce a requirement to grease the door mechanisms.
The finding was determined to be more than minor because it was associated with the
Procedure Quality attribute of the Barrier Integrity Cornerstone and affected the
cornerstone objective of providing reasonable assurance that physical design barriers
protect the public from radionuclide releases caused by accidents or events. The
inspectors determined that the finding was of very low safety significance because the
upper airlock inner door remained closed and the finding did not represent an actual
4
Enclosure
open pathway in the physical integrity of reactor containment. This finding has a cross-
cutting aspect in the area of Human Performance as defined in IMC 0305, H.2(c),
Resources, because the licensee did not ensure that procedures were complete and
were adequate to assure nuclear safety. (Section 4OA2)
B.
Licensee-Identified Violations
Three violations of very low safety significance that were identified by the licensee have
been reviewed by the inspectors. Corrective actions planned or taken by the licensee
have been entered into the licensees corrective action program. These violations and
corrective action tracking numbers are listed in Section 4OA7 of this report.
5
Enclosure
REPORT DETAILS
Summary of Plant Status
The plant began the inspection period at 100 percent power. On July 1, 2008, operators
reduced reactor power to 67 percent for planned maintenance and testing. The plant returned
to full power operation on July 2, 2008. On August 22, 2008, operators reduced reactor power
to about 93 percent to manage main condenser operations during warm weather conditions.
The plant returned to full power the next day. On September 14, 2008, operators reduced
reactor power to about 95 percent again due to warm weather and returned the plant to full
power on the same day. On September 20, 2008, operators reduced reactor power to about
60 percent for planned maintenance and testing. The plant returned to full power operation on
September 23, 2008. With the exception of planned downpowers for routine surveillance testing
and rod sequence exchanges, the plant remained at 100 percent power for the remainder of the
inspection period.
1.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and
1R01 Adverse Weather Protection (71111.01)
.5
Readiness For Impending Adverse Weather Condition - Severe Thunderstorm
Watch/Sighted Waterspout
a.
Inspection Scope
Since thunderstorms with potential tornados and high winds were forecast in the vicinity
of the facility for the week of July 21, 2008, the inspectors reviewed the licensees overall
preparations/protection for the expected weather conditions. The inspectors walked
down the ESW system, in addition to the licensees emergency alternating current (AC)
power systems, because their safety-related functions could be affected or required as a
result of high winds or tornado-generated missiles or the loss of offsite power. The
inspectors evaluated the licensee staffs preparations against the sites procedures and
determined that the staffs actions were adequate. During the inspection, the inspectors
focused on plant specific design features and the licensees procedures used to respond
to specified adverse weather conditions. The inspectors also toured the plant grounds to
look for any loose debris that could become missiles during a tornado. The inspectors
evaluated operator staffing and accessibility of controls and indications for those
systems required to control the plant. Additionally, the inspectors reviewed the Updated
Final Safety Analysis Report (UFSAR) and performance requirements for systems
selected for inspection, and verified that operator actions were appropriate as specified
by plant specific procedures. The inspectors also reviewed a sample of corrective action
program (CAP) items to verify that the licensee identified adverse weather issues at an
appropriate threshold and dispositioned them through the CAP in accordance with
station corrective action procedures. Documents reviewed are listed in the Attachment.
This inspection constituted one sample for readiness for impending adverse weather
conditions as defined in Inspection Procedure (IP) 71111.01-05.
6
Enclosure
b.
Findings
No findings of significance were identified.
.8
Readiness For Impending Adverse Weather Condition - Extreme Heat/Drought
Conditions
a.
Inspection Scope
The inspectors performed a detailed review during the week of July 14, 2008, of the
licensees procedures and preparations for operating the facility during an extended
period of time when ambient outside temperature was high and the ultimate heat sink
was experiencing elevated temperatures. The inspectors focused on plant specific
design features and implementation of the procedures for responding to or mitigating the
effects of these conditions on the operation of the emergency service water (ESW)
system and other selected systems. Inspection activities included a review of the
licensees adverse weather procedures, daily monitoring of the off-normal environmental
conditions, and that operator actions specified by plant specific procedures were
appropriate to ensure operability of the normal and emergency cooling systems.
Documents reviewed are listed in the Attachment.
This inspection constituted one sample for readiness for impending adverse weather
conditions as defined in IP 71111.01-05.
b.
Findings
No findings of significance were identified.
1R04 Equipment Alignment (71111.04)
.1
Quarterly Partial System Walkdowns
a. Inspection Scope
The inspectors performed partial system walkdowns of the following risk-significant
systems:
Division 3 diesel generator system during the week of August 25, 2008;
containment vessel and drywell purge system prior to welding replacement of
local leak rate test penetration V313-V314 test connection valve 1M14F0602,
during the week of September 22, 2008; and
high pressure core spray (HPCS) during a Division 1 outage during the week of
September 29, 2008.
The inspectors selected these systems based on their risk significance relative to the
Reactor Safety Cornerstones at the time they were inspected. The inspectors attempted
to identify any discrepancies that could impact the function of the system, and, therefore,
potentially increase risk. The inspectors reviewed applicable operating procedures,
system diagrams, UFSAR, Technical Specification (TS) requirements, outstanding work
orders (WOs), condition reports (CRs), and the impact of ongoing work activities on
redundant trains of equipment in order to identify conditions that could have rendered
7
Enclosure
the systems incapable of performing their intended functions. The inspectors also
walked down accessible portions of the systems to verify system components and
support equipment were aligned correctly and operable. The inspectors examined the
material condition of the components and observed operating parameters of equipment
to verify that there were no obvious deficiencies. The inspectors also verified that the
licensee had properly identified and resolved equipment alignment problems that could
cause initiating events or impact the capability of mitigating systems or barriers and
entered them into the CAP with the appropriate significance characterization.
Documents reviewed are listed in the Attachment.
These activities constituted three samples for partial system walkdowns as defined in
b. Findings
No findings of significance were identified.
.2
Semi-Annual Complete System Walkdown
a. Inspection Scope
During the months of July and August 2008 the inspectors performed a complete system
alignment inspection of the ESW system to verify the functional capability of the system.
This system was selected because it was considered both safety-significant and
risk-significant in the licensees probabilistic risk assessment. The inspectors walked
down the system to review mechanical and electrical equipment lineups, electrical power
availability, system pressure and temperature indications, as appropriate, component
labeling, component lubrication, component and equipment cooling, hangers and
supports, operability of support systems, and to ensure that ancillary equipment or
debris did not interfere with equipment operation. A review of a sample of past and
outstanding WOs was performed to determine whether any deficiencies significantly
affected the system function. In addition, the inspectors reviewed the CAP database to
ensure that system equipment alignment problems were being identified and
appropriately resolved. Documents reviewed are listed in the attachment.
These activities constituted one sample for a complete system walkdown as defined in
b. Findings
No findings of significance were identified.
1R05 Fire Protection (71111.05)
.1
Routine Resident Inspector Tours (71111.05Q)
a. Inspection Scope
The inspectors conducted fire protection walkdowns which were focused on availability,
accessibility, and the condition of firefighting equipment in the following risk-significant
plant areas:
8
Enclosure
Fire Zones 1CC-4 A,C,D, and E; Control Complex elevation 638 6;
Fire Zones 1CC-5 A, B and C; Control Complex elevation 654 6;
Emergency Service Water pumphouse;
Fire Zone 1DG-1A, Diesel Generator Building 6206 - Division 2 Diesel
Generator Room;
Fire Zone 1DG-1B, Diesel Generator Building 6206 - Division 3 Diesel
Generator Room;
Fire Zone 1DG-1C, Diesel Generator Building 6206 - Division 1 Diesel
Generator Room; and
Fire Zone 1DG-1D, Diesel Generator Building 6206 - Hallway.
The inspectors reviewed areas to assess if the licensee had implemented a fire
protection program that adequately controlled combustibles and ignition sources within
the plant, effectively maintained fire detection and suppression capability, maintained
passive fire protection features in good material condition, and had implemented
adequate compensatory measures for out of service, degraded or inoperable fire
protection equipment, systems, or features in accordance with the licensees fire plan.
The inspectors selected fire areas based on their overall contribution to internal fire risk
as documented in the plants Individual Plant Examination of External Events with later
additional insights, their potential to impact equipment which could initiate or mitigate a
plant transient, or their impact on the plants ability to respond to a security event. Using
the documents listed in the Attachment, the inspectors verified that fire hoses and
extinguishers were in their designated locations and available for immediate use; that
fire detectors and sprinklers were unobstructed, that transient material loading was
within the analyzed limits; and fire doors, dampers, and penetration seals appeared to
be in satisfactory condition. The inspectors also verified that minor issues identified
during the inspection were entered into the licensees CAP. Documents reviewed are
listed in the attachment.
These activities constituted seven quarterly samples for fire protection as defined in
b. Findings
Introduction: The inspectors identified a finding of very low safety significance and an
associated NCV of the Perry Nuclear Power Plant Operating License Condition C(6),
when licensee personnel degraded a fire barrier and failed to adhere to fire protection
program procedures.
Description: On August 18, 2008, while performing a walkdown of the ESW system in
the ESW pumphouse, the inspectors noticed that the double-door access to the diesel
fire pump (DFP) room was propped open. One of the doors was tied open with a rope
and the other was propped open with scaffolding material. Workers were in the process
of moving scaffolding and other material in and out of the DFP room for planned
maintenance. The doors had warning signs identifying them as fire-safety barriers and
also stated the requirement to notify the control room prior to impairing them. The
inspectors questioned the workers whether they were meeting the requirements for
impairing the door. The workers informed the inspectors that it was their understanding
that as long as personnel were in the vicinity of the door, they could impair the door
open.
9
Enclosure
The inspectors discussed this issue with the control room operators and inquired
whether the control room was aware of this specific impairment. Control room personnel
were not aware of an impairment authorized for the DFP door.
The inspectors continued the inspection and were informed by the maintenance services
supervisor that fixed fire impairments were no longer approved without proper
authorization. Licensee personnel removed the fixed impairments, and the doors were
subsequently held open as-needed by personnel in accordance with plant procedures.
The inspectors confirmed with the Secondary Alarm Station, which maintained a list of
current fire impairments, that the fixed impairments for the DFP room were not
requested and not approved in accordance with plant procedures. The inspectors also
confirmed with the fire marshal that there was not an approved impairment for the DFP
fire doors.
The licensee further determined that maintenance personnel had left the area while the
fire doors were impaired and, as such, the degraded fire barrier condition was left
unattended.
Analysis: The inspectors determined that the licensees failure to follow the procedural
requirements of the Perry Plant Fire Protection Program was a performance deficiency
warranting a significance evaluation.
The inspectors determined that the performance deficiency was more than minor in
accordance with IMC 0612, Appendix B, Issue Disposition Screening, because the
finding was associated with protection against external factors attribute of the Mitigating
Systems Cornerstone and affected the cornerstone objective of ensuring the availability,
reliability, and capability of systems that respond to initiating events to prevent
undesirable consequences. Specifically, by the inappropriate use of fixed impairments
on the fire doors between the DFP room and the ESW pumphouse, licensee personnel
removed a fire barrier affecting the safety-related building.
The inspectors evaluated the finding using IMC 0609, Appendix F, Fire Protection
Significance Determination Process. Because the finding involved fire doors, it was
assigned to the Fire Confinement finding category in accordance with table 1.1.1. The
finding was then assigned a High degradation rating in accordance with step 1.2.
Guidance in IMC 0609, Appendix F, Attachment 2, table A2.2 was also used to make
this determination. Step 1.3 then directed the inspectors to step 1.4 based on the Fire
Confinement category and High Degradation rating. In step 1.4, with an assumed
<3-day duration and a Generic Fire Frequency of 3E-2 based on a diesel generator
building, the resultant CDF (core damage frequency) value of 3E-4 required a Phase 2
analysis.
The inspectors performed a Phase 2 evaluation using IMC 0609, Appendix F, Fire
Protection SDP. The inspectors determined that there was not a credible fire scenario
relating to the performance deficiency associated with the blocked open fire door for the
DFP room. The inspectors evaluated fire scenarios for the diesel fire pump and its
associated fuel supply using a bounding 10 MegaWatt (MW) fire (the uppermost fire bin
size from IMC 0609, Appendix F, Table 2.3.1, Mapping of General Fire Scenario
Characterization Type Bins to Fire Intensity Characteristics). For evaluating fire
scenarios involving radiant heat, the inspectors used IMC 0609, Appendix F,
10
Enclosure
Table 2.3.2, Calculated Values (in feet) for Use in the Ball and Column Zone of
Influence Chart for Fires in an Open Location from Walls. The inspectors noted that
there was no equipment important to safety outside the fire door to the diesel fire pump
room within the radial zone of influence for a 10 MW fire. In addition, there was no
equipment inside the fire door within the radial zone of influence for a 200 kW fire
(the 98th percentile bin for a small electrical fire or solid and transient combustible fire).
The inspectors noted that there was no equipment directly above the door which could
be adversely affected by a plume originating near the fire door. The inspectors also
evaluated the potential for a damaging hot gas layer to develop from a 10 MW fire using
a CFAST (Consolidated Fire and Smoke Transport) fire simulation (publicly available
from www.nist.gov). Based on the simulation results, the inspectors determined that a
hot gas layer of approximately 588 degrees Fahrenheit (°F) could develop over the
period of 30 minutes. Such a temperature was below the damage threshold (625 °F) for
thermoset cables such as those used at the Perry Nuclear Power Plant. The CFAST
simulation was based on the ESW pump house having dimensions of 103 feet by 55 feet
by 65 feet high, and that the ESW pumphouse had five louvered ventilation openings of
7 feet wide by 5 feet high (four located 35 feet above the floor and one located 25 feet
above the floor), four louvered ventilation openings of 7 feet wide by 5.5 feet high
(located 50 feet above the floor). The inspectors assumed an opening fraction of 0.1 for
the louvered ventilation openings to be representative of closed ventilation louvers.
Mechanical ventilation, which would provide additional cooling, was not considered. The
CFAST default settings for the fuel (i.e., methane with a 0.3 radiative fraction) were used
for the 10 MW fire specified. As such, the inspectors considered the issue to be of very
low safety significance (i.e., Green) because there was not a credible fire scenario
associated with the performance deficiency.
This finding has a cross-cutting aspect in the area of Human Performance, H.4(a),
because the licensee did not ensure that appropriate human error prevention techniques
were used. Specifically, the pre-job brief did not adequately detail the appropriate
procedural requirements for fire impairments.
Enforcement: Perry Nuclear Power Plant Operating License Condition C(6) states, in
part, that FENOC shall implement and maintain in effect all provisions of the approved
fire protection program. As stated in Perry Administrative Procedure (PAP)-1910, "Fire
Protection Program", Revision 15, work and activities in the plant which present a
potential for creating fire hazards are controlled by this and other plant administrative
procedures/instructions. The control processes include, among other things, impairment
permits. Fire Protection Instruction (FPI)-A-C01, "Fire Protection Program Control
Processes," outlines the specific procedure to request fire impairments. Contrary to the
operating license condition as implemented through the procedures above, the licensee
utilized fixed fire door impairments without proper authorization or controls. Because
this violation was of very low safety significance and it was entered into the licensees
CAP as CR 08-44968, this violation is being treated as NCV, consistent with Section
VI.A.1 of the NRC Enforcement Policy (NCV 05000440/2008004-01).
11
Enclosure
1R06 Flood Protection Measures (71111.06)
.1
a. Inspection Scope
The inspectors reviewed selected risk important plant design features and licensee
procedures intended to protect the plant and its safety-related equipment from internal
flooding events. The inspectors reviewed flood analyses and design documents,
including the UFSAR, engineering calculations, and abnormal operating procedures to
identify licensee commitments. The specific documents reviewed are listed in the
Attachment to this report. In addition, the inspectors reviewed licensee drawings to
identify areas and equipment that may be affected by internal flooding caused by the
failure or misalignment of nearby sources of water, such as the fire suppression or the
circulating water systems. The inspectors also reviewed the licensees corrective action
documents with respect to past flood-related items identified in the CAP to verify the
adequacy of the corrective actions. The inspectors performed a walkdown of the
auxiliary building and the modification associated with the alternate decay heat removal
(ADHR) installation during the weeks of August 4 and 11, 2008, to assess the adequacy
of watertight doors and verify drains and sumps were clear of debris and were operable,
and that the licensee complied with its commitments. Documents reviewed are listed in
the attachment.
This inspection constituted one sample for internal flooding as defined in
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification Program
.1
Resident Inspector Quarterly Review (71111.11Q)
a. Inspection Scope
On July 23, 2008, the inspectors observed a crew of licensed operators in the plants
simulator during licensed operator requalification examinations to verify that operator
performance was adequate, evaluators were identifying and documenting crew
performance problems and training was being conducted in accordance with licensee
procedures. The inspectors evaluated the following areas:
licensed operator performance;
clarity and formality of communications;
ability to take timely actions in the conservative direction;
prioritization, interpretation, and verification of annunciator alarms;
correct use and implementation of abnormal and emergency procedures;
control board manipulations;
oversight and direction from supervisors; and
ability to identify and implement appropriate TS actions and Emergency Plan
actions and notifications.
12
Enclosure
The crews performance in these areas was compared to pre-established operator action
expectations and successful critical task completion requirements. Documents reviewed
are listed in the Attachment.
This inspection constitutes one quarterly sample for the licensed operator requalification
program as defined in IP 71111.11.
b. Findings and observations
After completing a training cycle for High Intensity Training, the licensee revised the
Plant Emergency Instruction flow charts to Emergency Operating Procedures in order to
be in alignment with industry standards. The licensee planned to fully implement the
new Emergency Operating Procedures after completion of the training cycle.
1R12 Maintenance Effectiveness (71111.12)
.1
Routine Quarterly Evaluations (71111.12Q)
a. Inspection Scope
The inspectors evaluated degraded performance issues involving the risk-significant
HPCS system. The inspectors reviewed events such as where ineffective equipment
maintenance had resulted in valid or invalid automatic actuations of engineered
safeguards systems and independently verified the licensee's actions to address system
performance or condition problems in terms of the following:
implementing appropriate work practices;
identifying and addressing common cause failures;
scoping of systems in accordance with 10 CFR 50.65(b) of the maintenance rule;
characterizing system reliability issues for performance;
charging unavailability for performance;
trending key parameters for condition monitoring;
ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification; and
verifying appropriate performance criteria for structures, systems, and
components/functions classified as (a)(2) or appropriate and adequate goals and
corrective actions for systems classified as (a)(1).
The inspectors assessed performance issues with respect to the reliability, availability,
and condition monitoring of the system. In addition, the inspectors verified maintenance
effectiveness issues were entered into the CAP with the appropriate significance
characterization. Documents reviewed are listed in the Attachment.
This inspection constitutes one quarterly sample for maintenance effectiveness as
defined in IP 71111.12-05.
b. Findings
No findings of significance were identified.
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Enclosure
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)
.1
Maintenance Risk Assessments and Emergent Work Control
a. Inspection Scope
The inspectors reviewed the licensee's evaluation and management of plant risk, for the
maintenance and emergent work activities affecting risk-significant and safety-related
equipment listed below to verify that the appropriate risk assessments were performed
prior to removing equipment for work:
suppression pool level instrument 'A' during the week of July 7, 2008;
diesel fire pump battery replacement during the week of July 28, 2008;
auxiliary building modifications during the week of August 4, 2008; and
motor feedwater pump during the week of August 4, 2008.
These activities were selected based on their potential risk significance relative to the
Reactor Safety Cornerstone. As applicable for each activity, the inspectors verified that
risk assessments were performed as required by 10 CFR 50.56(a)(4) and were accurate
and complete. When emergent work was performed, the inspectors verified that the
plant risk was promptly reassessed and managed. The inspectors reviewed the scope
of maintenance work, discussed the results of the assessment with the licensee's
probabilistic risk analyst or shift technical advisor, and verified plant conditions were
consistent with the risk assessment. The inspectors also reviewed TS requirements and
walked down portions of redundant safety systems, when applicable, to verify risk
analysis assumptions were valid and applicable requirements were met. Documents
reviewed are listed in the Attachment.
These activities constituted four samples for maintenance risk assessments and
emergent work controls as defined in IP 71111.13-05.
b. Findings
(1) Introduction: The inspectors identified a finding of very low safety significance and an
associated NCV of 10 CFR 50.65(a)(4) for failure to implement compensatory measures
for a risk management activity. The licensee failed to implement prescribed risk controls
associated with work affecting the low pressure core spray (LPCS) system.
Description: On August 6, 2008, during a plant tour, the inspectors were verifying the
licensees configuration control and compensatory measures for removal of auxiliary
building floor plugs following a tornado warning for Lake County earlier that morning.
Control room operators provided the inspectors with Engineering Evaluation Requests
p(EER) 600250251, 600308906, and 600472744 for the floor plug removal, which
provided the operators guidance and compensatory measures for addressing auxiliary
building and LPCS operability. The inspectors determined that the following hatch plugs
were removed: 620' West elevation; 620' East elevation; and 599' East elevation. The
inspectors noted that the three EERs did not allow the concurrent removal of all three
plugs and informed the control room operators of this observation. After a review of the
configuration against the engineering evaluations, the Shift Manager declared LPCS
inoperable and ordered the replacement of two of the building floor plugs.
14
Enclosure
The inspectors observed that the removal of the 620 East and 599 East elevation floor
plugs, which are above the LPCS pump motor, provided a direct vertical path to the
LPCS pump. In the near vicinity of the floor plug opening at ground level was a building
roll-up door that had no unique missile shield function as specified by Updated Safety
Analysis Report (USAR) Table 3.5-6. The inspectors considered that, during a high wind
event, a missile could enter the roll-up door that was near the floor plug opening. From
that location, the missile could drop unhindered onto the LPCS pump motor. The
inspectors also noted that workers had left a significant amount of equipment and
materials in the vicinity of the openings above the LPCS pump.
As stated in PAP-0205, Operability of Plant Systems, section 3.1, Revision 18,
administrative controls are those actions taken to control system or component
configuration in accordance with TS action requirements. The licensee did not have any
administrative controls delineated for this specific floor plug configuration for tornado or
high wind warnings. The licensee evaluation for the configuration of all three floor plugs
removed, update to EER 600472744, stated that LPCS should be conservatively
declared inoperable during high wind warnings. The licensee documented the issue in
CR 08-44524.
Analysis: The inspectors determined that the failure to implement administrative controls
for missile protection for a risk management activity was a performance deficiency. The
finding was determined to be more than minor because it was related to risk
management issues and met the guidance of IMC 0612, Appendix B, Section 3,
question (2) and question (5)(i), dated September 20, 2007. Specifically, the licensee
failed to provide administrative controls related to work affecting LPCS.
The inspectors, using IMC 0609, Appendix K, Maintenance Risk Assessment and
Risk Management SDP, Flowchart 2, dated May 19, 2005, determined that the finding
was of very low safety significance. The time that the plant was exposed to high wind
warnings was approximately four hours. The incremental core damage probability for
the duration of the procedure and for the critical step was less than 1 X 10-6. This finding
had a cross-cutting aspect in the area of Human Performance as defined in IMC 0305,
H.3(a), because the organization failed to adequately plan work activities that are
associated with risk.
Enforcement: 10 CFR 50.65(a)(4) requires the licensee to assess and manage the risk
associated with removing the barriers around the LPCS system. Contrary to this, the
licensee failed to manage the risk associated with the floor plug configuration in the
auxiliary building in that it was not in accordance with any of the licensee risk
evaluations, which resulted in not having appropriate administrative controls for high
winds. Because the violation was of very low safety significance and the issue was
entered into the licensees CAP (CR 08-44524), this violation is being treated as an
NCV, consistent with Section VI.A of the NRC Enforcement Policy
(2) Introduction: The inspectors identified a finding of very low safety significance and an
associated NCV of 10 CFR 50.65(a)(4) for failure to implement a procedurally-required
risk management activity for a protected train. The licensee performed work on
emergency closed cooling (ECC) 'A' when it was considered a protected train during a
Yellow Risk plant condition.
15
Enclosure
Description: On June 11, 2008, during a plant tour, the inspectors were verifying PNPP
No. 10244, "Protected Equipment Posting Checklist for RCIC Outage (Yellow)," dated
June 19, 2006, and observed work being performed on ECC 'A' heat exchanger near the
isolation valves. The ECC 'A' was listed as a protected train on checklist PNPP
No. 10244. The inspectors determined that the shift manager was not aware of the
activity and the engineers did not realize the component they were working on was
protected for risk-management reasons. After the inspectors notified the shift manager
of the work, the shift manager then provided the required controls to the activity
supervisor and work on ECC 'A' was authorized with the appropriate restraints. The
licensee also revised the protected train posting requirements for ECC A to include the
affected components. The licensee later determined that the work was authorized 3
days earlier, but that this was before the plant entered Yellow Risk and before ECC A
was considered protected.
Nuclear Operating Procedure (NOP)-OP-1007, Risk Determination, Section 4.16.3,
Revision 5, states for protected equipment that, "work is prohibited in these areas,
unless authorized." It further states, "Individuals needing to perform work in these
posted areas shall contact the Shift Manager or designee for permission to enter these
areas to perform work." In addition, licensee procedure PYBP-POS-2-2, "Protected
Equipment Postings," Section 4.3.1, Revision 6, further states that, "Work should not
normally be scheduled in posted areas as part of a routine workweek." The evolution
witnessed by the inspectors was related to a scheduled task of heat exchanger testing.
The licensee documented the issue in the CAP as CR 08-42164.
The inspectors noted other similar risk management issues during the inspection period
and were concerned whether the identified issues were representative of a
programmatic issue. In one example, on July 1, 2008, the inspectors identified that the
licensee had failed to post the annulus exhaust gas treatment system (AEGTS) 'A' as
protected equipment prior to removing AEGTS 'B' from service at approximately
3:30 a.m. for scheduled maintenance. The inspectors questioned the shift manager at
about 7:30 a.m. on July 1, 2008, to determine whether AEGTS 'A' was posted as a
protected train. The shift manager determined that AEGTS 'A' was not posted, but said
that the subsystem should be posted as protected in accordance with PYBP-POS-2-2.
Section 4.1.1 of PYBP-POS-2-2, stated that, "When a component is out-of-service for
greater than four hours and failure of the remaining component would cause entry into
Technical Specification (TS) 3.0.3," that protected equipment postings should be used.
In accordance with Perry TS 3.6.4.3, the loss of both trains of AEGTS requires entry into
limiting condition for operation (LCO) TS 3.0.3. The shift manager ordered the posting of
AEGTS A. At about 10:00 a.m., the inspectors performed a follow-up field walkdown to
verify the new postings and found that, while operators had subsequently posted
AEGTS 'A' in the control room, they had not posted the AEGTS 'A' room in the field. The
operators had considered the postings complete. The inspectors noted that this was
also contrary to PYBP-POS-2-2. The inspectors informed the shift manager of the
observation. At about 10:45 a.m., licensee personnel completed postings for AEGTS 'A'.
Analysis: The inspectors determined that the failure to implement a
procedurally-required risk-management activity for the ECC A protected train was a
performance deficiency. The finding was determined to be more than minor because it
was related to risk management issues and met the guidance of IMC 0612, Appendix B,
Section 3, question (2) and question (5)(i), dated September 20, 2007. Specifically, the
16
Enclosure
licensee failed to either prohibit work or provide required management oversight of work
on ECC 'A' while the plant was in Yellow Risk.
The inspectors, using IMC 0609, Appendix K, Maintenance Risk Assessment and Risk
Management SDP, flowchart 2, dated May 19, 2005, determined that the finding was of
very low safety significance. The time that the plant was in Yellow Risk was less than
one day, and ECC 'A' was determined to be operable. The incremental core damage
probability for the duration of the procedure and for the critical step was less than
1 X 10 6. This finding had a cross-cutting aspect in the area of Human Performance as
defined in IMC 0305 H.3(a), because the organization failed to adequately plan work
activities that are associated with risk.
Enforcement: 10 CFR 50.65(a)(4) requires the licensee to manage the increase in risk
resulting from maintenance activities. Contrary to this, the inspectors identified that work
was in progress on ECC 'A' when that sub-system was posted as a protected train and
the required administrative controls were not met. Because the violation was of very low
safety significance and the issue was entered into the licensees CAP (CR 08-42164),
this violation is being treated as an NCV, consistent with Section VI.A of the NRC
Enforcement Policy (NCV 05000440/2008004-03).
1R15 Operability Evaluations (71111.15)
.1
Operability Evaluations
a. Inspection Scope
The inspectors reviewed the following issues:
residual heat removal (RHR) 'C' pump minimum flow valve during the week of
July 21, 2008;
Divisional Class 1E safety batteries during the week of August 11, 2008;
ESW 'B' flange material during the week of September 1, 2008;
ADHR core bore during August and September;
ESW building ventilation dampers during the week of September 22, 2008;
reactor water clean-up (RWCU) system through-wall leakage downstream of the
regenerative heat exchanger during the week of September 22, 2008; and
service water make-up to the cooling tower flow path isolation capability while the
inboard isolation valve, OP41F420, was declared inoperable during the week of
September 22, 2008.
The inspectors selected these potential operability issues based on the risk-significance
of the associated components and systems. The inspectors evaluated the technical
adequacy of the evaluations to ensure that TS operability was properly justified and the
subject component or system remained available such that no unrecognized increase in
risk occurred. The inspectors compared the operability and design criteria in the
appropriate sections of the TS and USAR to the licensees evaluations, to determine
whether the components or systems were operable. Where compensatory measures
were required to maintain operability, the inspectors determined whether the measures
in place would function as intended and were properly controlled. The inspectors
determined, where appropriate, compliance with bounding limitations associated with the
evaluations. Additionally, the inspectors also reviewed a sampling of corrective action
17
Enclosure
documents to verify that the licensee was identifying and correcting any deficiencies
associated with operability evaluations. Documents reviewed are listed in the
Attachment.
These inspections constitute seven samples for operability evaluations as defined in
IP 71111.15.-05.
b. Findings
Introduction: A finding of very low safety significance and an associated NCV of
10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was
self-revealed for the failure to have documented instructions, procedures, or drawings
appropriate to the circumstances. The failure to have an approved work package prior
to boring holes in a seismically qualified structure was not in accordance with Perrys
work control procedures.
Description: On August 4, 2008, during dayshift, contractors performing work associated
with the ADHR project prepared to bore a 14-inch hole in the floor of the 599 level of the
auxiliary building. Holes were being drilled in this area in preparation for pipe
installations that were scheduled at a later date. Upon arrival to the work site, the
workers began the set-up process for the boring machine and discovered that some of
the material pre-staged for the job was incorrect. The supervisor then directed the
workers to set-up and bore an 8-inch hole which was located nearby. In preparation for
drilling operations, the floor had been marked-up with representations of the rebar
present in the floor and the locations for the holes on this level associated with the
ADHR project.
The workers placed the boring machine over a crosshair on the floor that was marked
CL AUX-8 and CL AUX-D. These marks indicated the intersection of the centerline of
columns 8 and D in the auxiliary building. The workers assumed that this mark was the
center for the 8-inch hole. This was not the correct location for the 8-inch hole. The
correct location for the 8-inch hole was marked, but was five to six feet away.
The incorrect positioning of the boring equipment was discovered during shift turnover
on August 4. As supervision began looking into this event they discovered that the work
package for the boring of the 8-inch hole had not been released. The only boring work
that had an approved work package was for the 14-inch holes. The 8-inch hole had
been bored without an approved work package.
Analysis: The inspectors determined that boring holes in a seismically qualified structure
without an approved work package was contrary to Perrys work control practices and
was a performance deficiency.
The finding was determined to be more than minor because the finding was associated
with the design control attribute of Mitigating Systems Cornerstone and affected the
cornerstone objective of ensuring the availability, reliability, and capability of systems
that respond to initiating events to prevent undesirable consequences. Specifically, the
licensee initiated work on a seismically qualified structure in the absence of an approved
work package. This instance resulted in the boring of a hole in a location other than that
which was planned, thus placing the structure in an unanalyzed condition. The licensee
18
Enclosure
subsequently conducted an analysis to demonstrate operability for the current
configuration.
The inspectors determined the finding could be evaluated using the SDP in accordance
with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 -
Initial Screening and Characterization of findings, Table 4a for the Mitigating System
Cornerstone. The inspectors answered yes to the question regarding design or
qualification deficiencies confirmed not to result in loss of operability. Therefore this
finding screens as Green, very low safety significance.
This finding has a cross-cutting aspect in the area of human performance because
personnel failed to hold an adequate pre-job brief, did not have proper documentation,
and proceeded in the face of unexpected circumstances. H.4(a)
Enforcement: Criterion V, Instructions, Procedures, and Drawings, of 10 CFR Part 50,
Appendix B, requires, in part, that activities affecting quality be prescribed by
documented instructions, procedures, or drawings, of a type appropriate to the
circumstances and that they be accomplished in accordance with these instructions,
procedures, or drawings. Contrary to this, on August 4, 2008, the licensee failed to have
work instructions appropriate to the circumstances prior to initiating work. Specifically,
the licensee initiated work on a seismically qualified structure in the absence of an
approved work package. Because this violation was of very low safety significance and
it was entered into the licensees CAP as CR 08-4431, this violation is being treated as
an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy
1R19 Post-Maintenance Testing (71111.19)
.1
Post-Maintenance Testing
a. Inspection Scope
The inspectors reviewed the following post-maintenance activities for review to verify
that procedures and test activities were adequate to ensure system operability and
functional capability:
suppression pool 'A' level instrument line testing during the week of
July 14, 2008;
AEGTS testing during the weeks of July 14 and 28, 2008;
RHR 'C' leak indication during the weeks of August 18 and 29, 2008;
RHR 'C' minimum flow pressure trip unit during the week of September 15, 2008;
service water system make-up to cooling tower inboard isolation valve
troubleshooting and repair following an in-service testing surveillance failure
during the week of September 22, 2008; and
containment atmosphere monitoring system testing requirements following
control room recorder replacements during the week of September 22, 2008.
These activities were selected based upon the structure, system, or component's ability
to impact risk. The inspectors evaluated these activities for the following (as applicable):
the effect of testing on the plant had been adequately addressed; testing was adequate
for the maintenance performed; acceptance criteria were clear and demonstrated
19
Enclosure
operational readiness; test instrumentation was appropriate; tests were performed as
written in accordance with properly reviewed and approved procedures; equipment was
returned to its operational status following testing (temporary modifications or jumpers
required for test performance were properly removed after test completion), and test
documentation was properly evaluated. The inspectors evaluated the activities against
TS, the UFSAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC
generic communications to ensure that the test results adequately ensured that the
equipment met the licensing basis and design requirements. In addition, the inspectors
reviewed corrective action documents associated with post-maintenance tests to
determine whether the licensee was identifying problems and entering them in the CAP
and that the problems were being corrected commensurate with their importance to
safety. Documents reviewed are listed in the Attachment.
This inspection constitutes six samples for post-maintenance testing as defined in
b. Findings
No findings of significance were identified.
1R22 Surveillance Testing (71111.22)
.1
Surveillance Testing
a. Inspection Scope
The inspectors reviewed the test results for the following activities to determine whether
risk-significant systems and equipment were capable of performing their intended safety
function and to verify testing was conducted in accordance with applicable procedural
and TS requirements:
suppression pool level 'A' testing during the week of June 30, 2008, (routine);
inservice ECC pump and valve inspection during the week of August 4, 2008,
(IST);
emergency diesel generator (EDG) exhaust hallway inspection during the week
of August 4, 2008, (routine);
testing of the diesel driven fire pump ventilation switch during the week of
August 25, 2008, (routine) ;
average power range monitor (APRM) channel calibration testing during the
week of August 25, 2008, (routine) ;
Division 3 EDG testing during the week of September 15, 2008, (routine);
APRM 'A' channel calibration testing during the week of September 15, 2008,
(routine); and
oscillating power range monitor (OPRM) channel 'A' functional testing during the
week of September 22, 2008, (routine).
20
Enclosure
The inspectors observed in plant activities and reviewed procedures and associated
records to determine the following:
did preconditioning occur;
were the effects of the testing adequately addressed by control room personnel
or engineers prior to the commencement of the testing;
were acceptance criteria clearly stated, demonstrated operational readiness, and
consistent with the system design basis;
plant equipment calibration was correct, accurate, and properly documented;
as-left setpoints were within required ranges; and the calibration frequency were
in accordance with TSs, the USAR, procedures, and applicable commitments;
measuring and test equipment calibration was current;
test equipment was used within the required range and accuracy; applicable
prerequisites described in the test procedures were satisfied;
test frequencies met TS requirements to demonstrate operability and reliability;
tests were performed in accordance with the test procedures and other
applicable procedures; jumpers and lifted leads were controlled and restored
where used;
test data and results were accurate, complete, within limits, and valid;
test equipment was removed after testing;
where applicable for inservice testing activities, testing was performed in
accordance with the applicable version of Section XI, American Society of
Mechanical Engineers code, and reference values were consistent with the
system design basis;
where applicable, test results not meeting acceptance criteria were addressed
with an adequate operability evaluation or the system or component was
declared inoperable;
where applicable for safety-related instrument control surveillance tests,
reference setting data were accurately incorporated in the test procedure;
where applicable, actual conditions encountering high resistance electrical
contacts were such that the intended safety function could still be accomplished;
prior procedure changes had not provided an opportunity to identify problems
encountered during the performance of the surveillance or calibration test;
equipment was returned to a position or status required to support the
performance of its safety functions; and
all problems identified during the testing were appropriately documented and
dispositioned in the CAP.
Documents reviewed are listed in the Attachment to this report.
This inspection constituted one in-service testing sample and seven routine surveillance
testing samples as defined in IP 71111.22.
b. Findings:
No findings of significance were identified.
21
Enclosure
1EP6 Drill Evaluation (71114.06)
.1
Training Observation
a.
Inspection Scope
The inspector observed a simulator training evolution for licensed operators on
September 15, 2008, which required emergency plan implementation by a licensee
operations crew. This evolution was planned to be evaluated and included in
performance indicator (PI) data regarding drill and exercise performance. The
inspectors observed event classification and notification activities performed by the crew.
The inspectors also attended the post-evolution critique for the scenario. The focus of
the inspectors activities was to note any weaknesses and deficiencies in the crews
performance and ensure that the licensee evaluators noted the same issues and entered
them into the CAP. As part of the inspection, the inspectors reviewed the scenario
package and other documents listed in the Attachment to this report.
This inspection constituted one sample of a training observation as defined in
b.
Findings
No findings of significance were identified.
2.
RADIATION SAFETY
Cornerstone: Occupational Radiation Safety
2OS1 Access Control to Radiologically Significant Areas (71121.01)
.1
Review of Licensee PIs for the Occupational Exposure Cornerstone
a.
Inspection Scope
The inspectors reviewed the licensees Occupational Exposure Control Cornerstone PIs
to determine whether the conditions resulting in any PI occurrences had been evaluated
and whether identified problems had been entered into the licensees CAP for resolution.
This inspection constitutes one sample as defined in IP 71121.01-5.
b.
Findings
No findings of significance were identified.
.2
Plant Walkdowns and Radiation Work Permit Reviews
a.
Inspection Scope
The inspectors assessed the adequacy of the licensees internal dose assessment
process for internal exposures in excess of 50 millirem committed effective dose
equivalent. There were no internal exposures greater than 50 millirem committed
effective dose equivalent.
22
Enclosure
This inspection constitutes one sample as defined in IP 71121.01-5.
The inspectors also reviewed the licensees physical and programmatic controls for
highly activated and/or contaminated materials (non-fuel) stored within the spent fuel
pool or other storage pools.
This inspection constitutes one sample for plant walkdowns and radiation work permit
reviews as defined in IP 71121.01-5.
b.
Findings
No findings of significance were identified.
.3
Problem Identification and Resolution
a.
Inspection Scope
The inspectors reviewed a sample of the licensees self-assessments, audits, licensee
even reports (LERs), and special reports related to the access control program to verify
that identified problems were entered into the CAP for resolution.
This inspection constitutes one sample as defined in IP 71121.01-5.
The inspectors reviewed corrective action reports related to access controls and any
high radiation area radiological incidents (issues that did not count as PI occurrences
identified by the licensee in high radiation areas less than 1R/hr). Staff members were
interviewed and corrective action documents were reviewed to verify that follow-up
activities were being conducted in an effective and timely manner commensurate with
their importance to safety and risk based on the following:
initial problem identification, characterization, and tracking;
disposition of operability/reportability issues;
evaluation of safety significance/risk and priority for resolution;
identification of repetitive problems;
identification of contributing causes;
identification and implementation of effective corrective actions;
resolution of NCVs tracked in the corrective action system; and
implementation/consideration of risk-significant operational experience feedback.
This inspection constitutes one sample as defined in IP 71121.01-5.
The inspectors evaluated the licensees process for problem identification,
characterization, and prioritization and verified that problems were entered into the
CAP and resolved. For repetitive deficiencies and/or significant individual deficiencies
in problem identification and resolution, the inspectors verified that the licensees
self-assessment activities were capable of identifying and addressing these deficiencies.
This inspection constitutes one sample as defined in IP 71121.01-5.
The inspectors reviewed licensee documentation packages for all PI events occurring
since the last inspection to determine if any of these PI events involved dose rates in
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Enclosure
excess of 25 R/hr at 30 centimeters or in excess of 500 R/hr at 1 meter. Barriers were
evaluated for failure and to determine if there were any barriers left to prevent personnel
access. Unintended exposures exceeding 100 millirem total effective dose equivalent
(or 5 rem shallow dose equivalent or 1.5 rem lens dose equivalent) were evaluated to
determine if there were any regulatory overexposures or if there was a substantial
potential for an overexposure.
This inspection constitutes one sample as defined in IP 71121.01-5.
b.
Findings
No findings of significance were identified.
.4
High Risk Significant, High Dose Rate, High Radiation Area and Very High Radiation
Area Controls
a.
Inspection Scope
The inspectors held discussions with the radiation protection manager concerning high
dose rate/high radiation areas and very high radiation area controls and procedures,
including procedural changes that had occurred since the last inspection, in order to
assess whether any procedure modifications substantially reduced the effectiveness and
level of worker protection.
This inspection constitutes one sample as defined in IP 71121.01-5.
The inspectors discussed with radiation protection supervisors the controls that were in
place for special areas of the plant that had the potential to become very high radiation
areas during certain plant operations. The inspectors assessed if plant operations
required communication beforehand with the radiation protection group, so as to allow
corresponding timely actions to properly post and control the radiation hazards.
This inspection constitutes one sample as defined in IP 71121.01-5.
b.
Findings
No findings of significance were identified.
.5
Radiation Worker Performance
a.
Inspection Scope
The inspectors reviewed radiological problem reports for which the cause of the event
was due to radiation worker errors to determine if there was an observable pattern
traceable to a similar cause and to determine if this perspective matched the corrective
action approach taken by the licensee to resolve the reported problems. Problems or
issues with planned or completed corrective actions were discussed with the radiation
protection manager.
This inspection constitutes one sample as defined in IP 71121.01-5.
24
Enclosure
b.
Findings
No findings of significance were identified.
.6
Radiation Protection Technician Proficiency
a.
Inspection Scope
The inspectors reviewed radiological problem reports for which the cause of the event
was radiation protection technician error to determine if there was an observable pattern
traceable to a similar cause and to determine if this perspective matched the corrective
action approach taken by the licensee to resolve the reported problems.
This inspection constitutes one sample as defined in IP 71121.01-5.
b. Findings
No findings of significance were identified.
4.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification (71151)
.1
Unplanned Scrams per 7000 Critical Hours
a.
Inspection Scope
The inspectors sampled licensee submittals for the Unplanned Scrams per 7000 Critical
Hours PI for the period from 3rd quarter 2007 through the 2nd quarter 2008. To determine
the accuracy of the PI data reported during those periods, PI definitions and guidance
contained in the NEI 99-02, Regulatory Assessment PI Guideline, Revision 5, was
used. The inspectors reviewed the licensees operator narrative logs, issue reports,
event reports and NRC inspection reports for the period of 3rd quarter 2007 through the
2nd quarter 2008 to validate the accuracy of the submittals. The inspectors also
reviewed the licensees issue report database to determine if any problems had been
identified with the PI data collected or transmitted for this indicator. Documents reviewed
are listed in the Attachment to this report.
This inspection constituted one sample for unplanned scrams per 7000 critical hours as
defined in IP 71151-05.
b.
Findings
No findings of significance were identified.
.4
Safety System Functional Failures
a. Inspection Scope
The inspectors sampled licensee submittals for the Safety System Functional Failures PI
for the period from the 3rd quarter 2007 through the 2nd quarter 2008. To determine the
accuracy of the PI data reported during those periods, PI definitions and guidance
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Enclosure
contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory
Assessment PI Guideline, Revision 5, and NUREG-1022, Event Reporting Guidelines
10 CFR 50.72 and 50.73" definitions and guidance, were used. The inspectors reviewed
the licensees operator narrative logs, operability assessments, maintenance rule
records, maintenance WOs, issue reports, event reports and NRC integrated inspection
reports for the period of July 1, 2007 through June 30, 2008, to validate the accuracy of
the submittals. The inspectors also reviewed the licensees issue report database to
determine if any problems had been identified with the PI data collected or transmitted
for this indicator. Documents reviewed are listed in the Attachment to this report.
This inspection constituted one sample for safety system functional failures as defined in
b. Findings
No findings of significance were identified.
.9
Mitigating Systems Performance Index - Cooling Water Systems
a. Inspection Scope
The inspectors sampled licensee submittals for the Mitigating Systems Performance
Index (MSPI) - Cooling Water Systems PI for the period from 3rd quarter 2007 through
the 2nd quarter 2008. To determine the accuracy of the PI data reported during those
periods, PI definitions and guidance contained in the NEI 99-02, Regulatory
Assessment PI Guideline, Revision 5, was used. The inspectors reviewed the
licensees operator narrative logs, issue reports, MSPI derivation reports, event reports
and NRC integrated inspection reports for the period 3rd quarter 2007 through the
2nd quarter 2008 to validate the accuracy of the submittals. The inspectors reviewed the
MSPI component risk coefficient to determine if it had changed by more than 25 percent
in value since the previous inspection, and if so, that the change was in accordance with
applicable NEI guidance. The inspectors also reviewed the licensees issue report
database to determine if any problems had been identified with the PI data collected or
transmitted for this indicator and none were identified. Documents reviewed are listed in
the Attachment to this report.
This inspection constituted one sample for MSPI cooling water systems as defined in
b. Findings
No findings of significance were identified.
Cornerstone: Public Radiation Safety
.10
Reactor Coolant System Specific Activity
a. Inspection Scope
The inspectors sampled licensee submittals for the Reactor Coolant System Specific
Activity PI for Perry Station Unit 1 for the period from the third quarter 2007 through the
26
Enclosure
second quarter 2008. To determine the accuracy of the PI data reported during those
periods, PI definitions and guidance contained in the NEI 99-02, Regulatory
Assessment PI Guideline, Revision 5, was used. The inspectors reviewed the
licensees reactor coolant system chemistry samples, TS requirements, issue reports,
event reports and NRC Integrated Inspection Reports for the period of July 2007 through
August 2008 to validate the accuracy of the submittals. The inspectors also reviewed
the licensees issue report database to determine if any problems had been identified
with the PI data collected or transmitted for this indicator and none were identified. In
addition to record reviews, the inspectors observed a chemistry technician obtain and
analyze a reactor coolant system sample. Documents reviewed are listed in the
Attachment to this report.
This inspection constituted one sample for reactor coolant system specific activity as
defined in IP 71151-05.
b. Findings
No findings of significance were identified.
.15
Occupational Exposure Control Effectiveness
a. Inspection Scope
The inspectors sampled licensee submittals for the Occupational Radiological
Occurrences PI for the period from the 4th quarter 2007 through the 2nd quarter 2008. To
determine the accuracy of the PI data reported during those periods, PI definitions and
guidance contained in the NEI 99-02, Regulatory Assessment PI Guideline, Revision 5,
was used. The inspectors reviewed the licensees assessment of the PI for occupational
radiation safety to determine if indicator-related data was adequately assessed and
reported. To assess the adequacy of the licensees PI data collection and analyses, the
inspectors discussed with radiation protection staff, the scope and breadth of its data
review, and the results of those reviews. The inspectors independently reviewed
electronic dosimetry dose rate and accumulated dose alarm and dose reports and the
dose assignments for any intakes that occurred during the time period reviewed to
determine if there were potentially unrecognized occurrences. The inspectors also
conducted walkdowns of numerous locked high and very high radiation area entrances
to determine the adequacy of the controls in place for these areas. Documents reviewed
are listed in the Attachment to this report.
This inspection constituted one sample for occupational radiological occurrences as
defined in IP 71151-05.
b. Findings
No findings of significance were identified.
27
Enclosure
4OA2 Identification and Resolution of Problems (71152)
Cornerstone: Initiating Events, Mitigating Systems, Barrier Integrity, and
.1
Routine Review of Items Entered Into the CAP
a.
Inspection Scope
As part of the various baseline IPs discussed in previous sections of this report, the
inspectors routinely reviewed issues during baseline inspection activities and plant
status reviews to verify that they were being entered into the licensees CAP at an
appropriate threshold, that adequate attention was being given to timely corrective
actions, and that adverse trends were identified and addressed. Attributes reviewed
included: the complete and accurate identification of the problem; that timeliness was
commensurate with the safety significance; that evaluation and disposition of
performance issues, generic implications, common causes, contributing factors, root
causes, extent-of-condition reviews, and previous occurrence reviews were proper and
adequate; and that the classification, prioritization, focus, and timeliness of corrective
actions were commensurate with safety and sufficient to prevent recurrence of the issue.
Minor issues entered into the licensees CAP as a result of the inspectors observations
are included in the attached List of Documents Reviewed.
These routine reviews for the identification and resolution of problems did not constitute
any additional inspection samples. Instead, by procedure they were considered an
integral part of the inspections performed during the quarter and documented in
Section 1 of this report.
b. Findings
No findings of significance were identified.
.2
Daily Corrective Action Program Reviews
a. Inspection Scope
In order to assist with the identification of repetitive equipment failures and specific
human performance issues for follow-up, the inspectors performed a daily screening of
items entered into the licensees CAP. This review was accomplished through
inspection of the stations daily CR packages.
These daily reviews were performed by procedure as part of the inspectors daily plant
status monitoring activities and, as such, did not constitute any separate inspection
samples.
b. Findings
No findings of significance were identified.
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Enclosure
.5
Selected Issue Follow-Up Inspection: Containment Airlocks
a. Inspection Scope
The inspectors selected a CR for detailed annual sample review (CR 08-44698). The
CR was associated with an adverse trend of containment airlock failures. The report
was reviewed to ensure that the full extent of the issue was identified, an appropriate
evaluation was performed, and appropriate corrective actions were specified and
prioritized. The inspectors evaluated the report against the requirements of the
licensees CAP as delineated in NOP-LP-2001-01, Condition Report Process,
Revision 8, and 10 CFR Part 50, Appendix B.
This activity constitutes the first of two samples for an in-depth review as defined in
b. Findings
Introduction: A finding of very low safety significance (Green) and an associated NCV of
TS 5.4, Procedures, was self-revealed when a containment airlock door seal failed
during routine operations.
Description: On June 1, 2008, a licensee operator exited the containment building
through the upper airlock. When the operator closed the airlock outer door and operated
the door hand wheel, the light that provided indication for one of the doors seals failed to
illuminate. The operator made additional attempts to operate the door, but the doors
small seal would not inflate. The licensee declared the upper airlock outer door
inoperable and placed administrative controls on the inner door to ensure it was closed.
Licensee personnel inspected the outer doors seal mechanism and determined that a
3-way ball valve, 1P53F0591A, associated with the small seal had failed. The valve
stem had separated from the valve ball.
Licensee maintenance personnel removed the failed valve, noted valve body damage,
and determined that the valve needed to be rebuilt using a new valve body. The ball
valve 1P53F0591A was rebuilt, installed, and then tested with satisfactory results on
June 4, 2008.
Licensee maintenance and engineering personnel investigated the cause of the valve
failure. During inspection of the removed components, licensee personnel noted that
significant metal loss had occurred on the valve stem where it interfaced with the ball
slot. The inner ring of the valve body was also worn. The licensee initially determined
through engineering inspections and interviews with maintenance personnel, that
contrary to valve assembly procedures, a valve stem seal ring may not have been
installed during the last valve assembly. The seal ring was designed to prevent contact
between the stem and the valve body. The lack of a seal ring would have resulted in
metal to metal contact, galling, and damage to the valve during door operations.
The licensee could not find evidence of an installed slip ring during the initial
investigation. However, subsequent licensee laboratory testing results of the valve
internals indicated possible trace amounts of chemical residue on metal valve
component surfaces that could be consistent with the presence of an installed slip ring at
29
Enclosure
some time in the past. The laboratory personnel used an electron microscope to identify
the chemical traces.
The valve had been last worked on March 26, 2008. During this maintenance, a new
valve body was installed and the internals were rebuilt. The new valve body was a
replacement for the original valve body that had been in use for over 20 years.
The inspectors reviewed the March 26, 2008, work documentation and noted that
workers listed two slip rings as used during the work. The inspectors further noted that
the work procedures required the use of four stem slip rings. The inspectors questioned
licensee maintenance personnel on the discrepancy. During interviews with the
inspectors, licensee maintenance personnel stated that they believed all four slip rings
were used but that they mistakenly only documented the use of two slip rings.
The licensee later informed the inspectors that there was not a high level of certainty
whether the laboratory test results supported a conclusion that a slip ring had been
installed. The laboratory had later questioned the accuracy of the results due to the
minute amount of chemicals that were detected.
While the question of whether a stem slip ring was installed per procedure was not
conclusively resolved, the inspectors considered that the valve failed and exhibited
significant degradation in less than 3-months of routine use after it had been replaced.
Therefore, the inspectors determined that the March 26, 2008, procedures associated
with valve maintenance were not appropriate to the circumstances. Specifically, the
maintenance resulted in an unsatisfactory condition of the valve.
Other doors on both upper and lower containment airlocks were potentially affected by
past performance of airlock maintenance procedure Generic Mechanical Instruction
(GMI)-0176, Containment Airlock Door Maintenance. The licensee conducted a review
of the other airlock door seal mechanisms and reworked the lower and upper airlock
door mechanisms. The licensee identified several deficiencies during their rework of the
airlock doors, including: (1) inadequate procedure guidance for mechanism assembly
relative to worker training; (2) failure to grease the door mechanisms due to a dropped
maintenance task; and (3) maintenance frequencies that were not commensurate with
usage frequency of the doors. As part of their corrective action, the licensee
(1) conducted worker training; (2) planned to revise the airlock maintenance procedures
to include additional guidance; (3) planned to increase the maintenance frequency of the
airlocks; and (4) planned to reintroduce a requirement to grease the door mechanisms.
The inspectors previously noted that the licensees maintenance program associated
with the containment airlocks had resulted in frequent airlock failures. A programmatic
deficiency associated with the licensees maintenance and testing of the airlocks was
described in NCV 05000440/2007002-02.
Analysis: The inspectors determined that the failure to implement maintenance
procedures that were appropriate to the circumstances on March 26, 2008, was a
performance deficiency.
The finding was determined to be more than minor because the finding was associated
with the Procedure Quality attribute of the Barrier Integrity Cornerstone attribute and
affected the cornerstone objective of providing reasonable assurance that physical
30
Enclosure
design barriers (fuel cladding, reactor coolant system, and containment) protect the
public from radionuclide releases caused by accidents or events. Specifically, the
finding resulted in the degradation and failure of a containment door seal.
The inspectors determined the finding could be evaluated using the SDP in accordance
with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 -
Initial Screening and Characterization of findings, Table 4a for the Barrier Integrity
(Containment Barriers) Cornerstone. The inspectors determined that the finding did not
represent an actual open pathway in the physical integrity of reactor containment
because the upper airlock inner door remained closed. Therefore the finding screened
as Green.
This finding has a cross-cutting aspect in the area of Human Performance, H.2.c.,
Resources, because the licensee did not ensure that procedures were complete and
were adequate to assure nuclear safety. Specifically, the implementation of GMI-0176
resulted in the failure of valve 1P53F0591A, associated with a containment airlock seal.
Enforcement: Criterion V, Instructions, Procedures, and Drawings, of 10 CFR Part 50,
Appendix B, requires, in part, that activities affecting quality be prescribed by
documented instructions, procedures, or drawings, of a type appropriate to the
circumstances and be accomplished in accordance with these instructions, procedures,
or drawings. Contrary to this, on March 26, 2008, the licensee failed to implement
airlock maintenance procedures appropriate to the circumstances. Specifically, the
airlock maintenance procedures were not appropriate to the circumstances in that the
implementation of the procedures resulted in failure of the containment upper airlock
inner door seal on June 1, 2008. Because this violation was of very low safety
significance and it was entered into the licensees CAP as CR 08-41097, this violation is
being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy
as NCV 05000440/2008004-05, and closes URI 05000440/2008003-01.
.6
Selected Issue Follow-Up Inspection: ESW 'C' Valve Failure Affecting HPCS
a.
Inspection Scope
The inspectors selected a CR for detailed annual sample review (CR 08-40969). The
CR was associated with an inoperability of the HPCS system that was identified on
May 26, 2008. The report was reviewed to ensure that the full extent of the issue was
identified, an appropriate evaluation was performed, and appropriate corrective actions
were specified and prioritized. The inspectors evaluated the report against the
requirements of the licensees CAP as delineated in NOP-LP-2001-01, "Condition
Report Process", Revision 8, and 10 CFR 50, Appendix B.
This activity constitutes the second of two samples for an in-depth review as defined by
b. Findings
A licensee-identified violation is discussed in Section 4OA7 of this report.
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Enclosure
4OA3 Follow-up of Events and Notices of Enforcement Discretion (71153)
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and
.1
(Closed) LER 05000440/2008-001-00: Condition Prohibited by Technical Specifications
Due to Unrecognized Reactor Core Isolation Cooling Inoperability
On January 14, 2008, during preparation for planned maintenance, the licensee
identified that the reactor core isolation cooling (RCIC) flow controller voltage output
changed independently of any alteration in system input. The RCIC system was
declared inoperable. The licensee conducted an investigation that determined several
instances of inadequate voltage output dating back to December 10, 2007. Therefore,
the RCIC system was inoperable for 35 days and the licensee failed to meet the
requirements of TS 3.5.3. As stated in TS 3.5.3, the required action is to verify HPCS is
operable within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />; and restore the RCIC system to operable status in 14 days; or be
in hot standby within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> when neither of these conditions is met. When the
licensee discovered the RCIC system inoperable on January 14, 2008, the licensee did
meet the requirements of TS 3.5.3.
The licensee's investigation and troubleshooting could not determine the exact cause of
the controller output deviation, but listed the possible cause as one of the following four
replaced components: the Bailey 701 flow controller and connector, the power supply,
the ramp generator/signal converter, or the computer input circuit board. The
investigation stated that equipment reliability issues of these components could have
contributed to this failure, but the licensee considers that the anomaly was most likely
introduced into the system during the numerous flow controller changes performed
during November and December 2007.
On April 16, 2008, the licensee observed degraded RCIC flow controller output voltage,
but the output voltage met operability requirements. The licensee investigated the cause
and established a monitoring program to ensure RCIC system operability. On
April 24, 2008, the RCIC flow controller voltage output degraded to a point where the
licensee declared RCIC inoperable. A spare Bailey 701 controller (with previous service
life) was installed, and RCIC was declared operable on April 24, 2008. On
April 25, 2008, the licensee installed new NUS controllers that were designed to replace
the obsolete Bailey 701 controllers.
The Bailey 701 flow controller installed from January to April 2008 was evaluated by the
licensee's Beta lab. The lab was unable to identify the precise failure mechanism, but
concluded that the most likely portions of the controller causing this degradation were
the high output limit circuit (diodes, potentiometers, resistors) and the internal controller
power supply (capacitors, diodes, resistors, transistors, transformer). The investigation
concluded the April 2008 degraded failure was caused by age/cyclic duty degradation of
flow controller subcomponents. The investigation also noted that previous Bailey 701
flow controller failures were attributed to controller subcomponent aging as the major
contributor for the previous controller malfunctions.
The inspectors' discussion with the licensee concerning the two failures of the RCIC
controller system determined that the two inoperability periods mentioned here were due
to different equipment issues, which included the degradation of internal components of
32
Enclosure
the RCIC flow controller. Since the installation of the NUS flow controller, there have
been no observed operability issues with RCIC as of the date of this report.
Licensee corrective actions included replacement of the obsolete Bailey 701 controllers
with NUS controllers, and implemented a 12-year replacement/refurbishment
maintenance requirement of the RCIC flow controllers. This issue was found to be a
licensee-identified violation and is documented in section 4OA7. The licensee
documented the issue in CRs 08-38443 and 08-39111. This LER is closed.
This review represents the first of five samples as defined in IP 71153-05.
.2
Failure to Adequately Manage Risk Associated With Working Around a Risk-Significant
Underground Vault
a. Inspection Scope
The inspectors responded to an incident that occurred during routine maintenance
activities for dewatering underground vaults when the man-hole cover was dropped into
the vault area. The inspectors inspected the circumstance of the event, the impact on
plant safety, licensee response, and regulatory issues.
b. Findings
Introduction: A Green finding (FIN) of very low safety significance was self-revealed
when the licensee failed to manage risk when lifting a man-hole cover for an
underground vault containing risk-significant cables.
Description: On July 30, 2008, while preparing to dewater an underground vault,
man-hole number Eight, licensee personnel inadvertently dropped the man-hole cover
into the vault area. The vault area contained eight electrical conduits used for
indications and switchyard breaker controls affecting offsite power. The purpose of
those controls was fault indication and isolation of the four breakers associated with the
west bus of the switchyard. The licensee determined that the falling cover could have
damaged the control cables and this could have affected controls associated with the
supply of offsite power to the plant and plant stability. Without the fault protection
provided by the circuits, a breaker fault would lead to an off-site circuit protection
response and a loss of offsite power. The licensee determined that the dropped
man-hole cover fell down the side of the vault and did not impact or damage any of the
eight conduits.
The licensee's investigation determined that one of the workers involved with lifting the
man-hole cover was not ready to perform this task when the other technician lifted his
end of the cover. The licensee determined that the pre-job brief did not address the
possibility of dropping the cover and its possible impact to plant operations. Therefore,
the pre-job brief did not identify the removal of the man-hole cover as a critical task
requiring additional oversight. The investigation also identified inadequate
communications between the two workers as a contributing cause because the one
worker did not receive verbal confirmation from the other worker that he was prepared to
lift the cover.
33
Enclosure
The licensee's procedure, NOBP-LP-2604, "Effective Job Briefs," Revision 2, stated, in
4.2.1 (9), that a pre-job brief should summarize the critical steps, error-likely situations;
anticipate the potential errors for each identified critical step; and evaluate and establish
contingencies to prevent and catch errors. This procedure defined a critical step in 3.1
as, "a procedure step or action that, if performed incorrectly, will cause immediate,
irreversible, intolerable harm to plant equipment, people, or significantly impact plant
operation." Contrary to this standard, the licensee failed to identify the lifting of the man-
hole cover as a critical step and therefore did not institute error prevention tools for this
evolution.
Analysis: The inspectors determined that the failure to properly manage risk of the
underground vault was a performance deficiency warranting a significance evaluation in
accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue
Disposition Screening, issued on September 20, 2007. The inspectors determined that
the finding was more than minor because it was related to maintenance risk assessment
and risk management issues. Specifically, the licensee failed to manage risk for
maintenance activities associated with the electrical switchyard, including the
underground vaults, which could increase the likelihood of a loss of offsite power.
The inspectors performed a significance determination of this issue using IMC 0609,
Significance Determination Process, dated January 10, 2008, and IMC 0609.04, Initial
Screening and Characterization of Findings, dated January 10, 2008. The issue
screened as a transient initiator contributor. As such, the finding was of very low safety
significance because all mitigation equipment or functions were available. The primary
cause of this finding was related to the cross-cutting aspect in the area of Human
Performance because the organization failed to ensure the use of human error
prevention techniques commensurate with the risk of the assigned task H.4(a).
Enforcement: The inspectors determined that no violation of regulatory requirements
occurred because the electrical conduits in man-hole number Eight were not a
safety-related system covered by 10 CFR Part 50, Appendix B. The licensee entered
this issue into their CAP, CR 08-43997. (FIN 05000440/2008004-06)
This review represents the second of five samples as defined in IP 71153-05.
.3
Loss of Configuration Control of the Hydrogen Water Chemistry Injection System
Resulting in High Radiation Levels
a. Inspection Scope
The inspectors observed a planned downpower for maintenance and responded to an
incident that occurred during the evolution when operators received High Radiation
alarms for the Main Steam lines. The inspectors reviewed the circumstance of the
event, the impact on plant safety, licensee response, and regulatory issues.
b. Findings
Introduction: A Green finding (FIN) of very low safety significance was self-revealed
when high radiation level alarms were received on the main steam lines during a
reduction in reactor power. Technicians had failed to adhere to surveillance test
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Enclosure
procedures and the hydrogen water chemistry (HWC) injection system had been
inadvertently placed in manual.
Description: On June 28, 2008, while reducing power to 60 percent power for control
rod exercise, operators received main steam line high radiation level alarms when
reactor power was at 65 percent. Initially, the cause of the high radiation levels was
unknown to plant operators.
Operators responded by stabilizing reactor power and entering Plant Emergency
Instruction PEI-N11, Containment Leakage Control, and Off-Normal Instruction
ONI-J11, Gross Fuel Cladding Failure. Normal radiation levels for the main steam
lines were about 470 millirem per hour, and levels during the event were as high as 740
millirem per hour.
Operators investigating the cause of the high radiation levels determined that the HWC
injection system was in manual mode, and that the system was injecting at a rate
appropriate for 100 percent reactor power. Operators returned the HWC injection
system to automatic mode so that the injection rate would adjust appropriately to reactor
power levels. This returned radiation levels back to the normal range and operators
exited the plant emergency instruction and off-normal procedure.
The licensee's investigation determined that during a surveillance test conducted on
June 12, 2008, technicians used the HWC computer interface panel to monitor system
status in an effort to limit their radiation exposure while performing the test. The
surveillance, SVI-N64-T8021-A, "Main Condenser Offgas H2/O2 Monitor Channel A
Functional," Revision 7, did not allow for the use of the HWC monitor panel during the
surveillance. While using the panel, technicians inadvertently placed the HWC system in
manual mode, and with no procedural guidance to use the panel, they did not ensure
that the HWC system was in the correct mode of operation after completing their activity.
The investigation also determined that technicians considered the use of the HWC
computer interface panel as an undocumented enhancement to the surveillance
procedure to limit their radiation exposure. The technicians did not communicate this
practice to licensee management for proper review.
The licensee's Nuclear Operating Procedure (NOP)-LP-2601, "Procedure Use and
Adherence," Revision 1, states in 4.1.1, "Procedures shall be used and adhered to as
written without deviating from the original intent and purpose." Contrary to this standard,
licensee personnel did not adhere to the surveillance procedure when they manipulated
the HWC system.
Analysis: The inspectors determined that the failure of licensee personnel to adhere to
surveillance test procedures was a performance deficiency warranting a significance
evaluation in accordance with IMC 0612, ?Power Reactor Inspection Reports,
?Appendix B, ?Issue Disposition Screening,? issued on September 20, 2007. The
inspectors determined that the finding was more than minor because it was associated
with the operating equipment lineup of the configuration control attribute of the initiating
events cornerstone and adversely affected the cornerstone objective of limiting the
likelihood of events that upset plant stability. Specifically, the finding resulted in
unexpected high radiation levels in the plant, entrance into plant emergency procedures,
and challenged operators during a plant power maneuver.
35
Enclosure
The inspectors performed a significance determination of this issue using IMC 0609,
Significance Determination Process, dated January 10, 2008, and IMC 0609.04, Initial
Screening and Characterization of Findings, dated January 10, 2008. The issue
screened as a transient initiator contributor. As such, the finding was of very low safety
significance because all mitigation equipment or functions were available. The finding
had a cross-cutting aspect in the area of Human Performance because the licensee
failed to define and effectively communicate expectations regarding procedural
compliance and personnel did not follow procedures. Specifically, the technicians had
considered the manipulation of the HWC system to be an accepted practice though it
was contrary to the test procedure. H.4(b)
Enforcement: The inspectors determined that no violation of regulatory requirements
had occurred because the HWC injection system is not a safety-related system covered
by 10 CFR Part 50, Appendix B. The licensee entered this issue into their CAP as
CR 08-42529. (FIN 0500440/2008004-07)
This review represents the third of five samples as defined in IP 71153-05.
.4
(Closed) LER 0500440/2008-003-00: Inoperable High Pressure Core Spray System
Results in Loss of Safety Function
On May 28, 2008, the licensee identified, during an ESW 'C' subsystem draindown
surveillance, that ESW 'C' would fail to maintain system keepfill pressure during a loss of
offsite power event. ESW 'C' supported operation of HPCS, and both ESW 'C' and
HPCS were declared inoperable. The licensee inspected the ESW 'C' discharge check
valve and discharge valve. The licensee concluded the check valve was intermittently
stuck open during the surveillance test. The ESW 'C' discharge valve was not fully
seated and technicians made adjustments to the motor-operated valve (MOV) to ensure
complete closure. On June 1, 2008, repairs were completed and the ESW 'C' passed
the loop draindown surveillance, and both HPCS and ESW 'C' were declared operable.
The HPCS is a single train emergency core cooling system (ECCS) and this unplanned
inoperability represented a condition that could have prevented the fulfillment of the
safety function of HPCS when needed to mitigate the consequences of an accident.
During the licensee's investigation and troubleshooting, personnel observed leakage
past the ESW 'C' discharge valve and determined that the valve was approximately four
degrees from the optimum closed position. The licensee reset the closed limit switch of
the ESW 'C' discharge valve to ensure optimum closure of the valve by the valve motor
operator. The licensee determined that the ESW 'C' discharge valve was removed on
June 29, 2007, when ESW 'C' failed the loop draindown test. Inspection of the
discharge internals identified heavily corroded valve internals, and the ESW 'C'
discharge valve was replaced. The only post-maintenance test conducted was the
surveillance for ESW 'C' loop draindown test. No post-maintenance test was conducted
for leak tightness and proper MOV adjustments.
36
Enclosure
Licensee's corrective actions included adjustment of the MOV closed limit switch, the
development of a leak test and MOV testing, and the performance of this testing during
the next refueling outage. This issue was a licensee-identified violation and is
documented in section 4OA7. The licensee documented the issue in CR 08-40969.
This LER is closed.
This review represented the fourth of five samples as defined in IP 71153-05.
.5
Reactor Water Cleanup (RWCU) Pipe Weld Failure
a. Inspection Scope
During the week of September 22, 2008, the inspectors observed the licensees
response to a crack that developed in a RWCU system pipe weld located downstream of
the non-regenerative heat exchanger. The licensee isolated the RWCU system,
performed additional inspections, and repaired the weld. The inspectors reviewed the
circumstances of the event, the impact on plant safety, the licensees response, and any
regulatory issues.
This review represented the fifth of five samples as defined in IP 71153-05.
b. Findings
No findings of significance were identified.
4OA5 Other Activities
.1
Quarterly Resident Inspector Observations of Security Personnel and Activities
a.
Inspection Scope
During the inspection period, the inspectors conducted observations of security force
personnel and activities to ensure that the activities were consistent with licensee
security procedures and regulatory requirements relating to nuclear plant security.
These observations took place during both normal and off-normal plant working hours.
These quarterly resident inspector observations of security force personnel and activities
did not constitute any additional inspection samples. Rather, they were considered an
integral part of the inspectors' normal plant status reviews and inspection activities.
b.
Findings
No findings of significance were identified.
.2
Independent Effectiveness Assessment of the Training Required by the NRCs
August 15, 2007, Confirmatory Order (92702)
a.
Inspection Scope
On August 15, 2007, the NRC issued Confirmatory Order EA-07-199 (Order) that
formalized commitments made by the FirstEnergy Nuclear Operating Company
37
Enclosure
(FENOC). The FENOC commitments were documented in its July 16, 2007, letter
responding to the NRCs May 14, 2007, Demand for Information (DFI).
The Order required, in part, that the licensee conduct regulatory sensitivity training for
selected FENOC and non-FENOC FirstEnergy employees, to ensure those employees
identify and communicate information that has the potential for regulatory impact at any
FENOC nuclear site or within the nuclear industry, to the NRC. This requirement was
inspected and documented in Inspection Report (IR) 05000440/2007005. That IR also
lists all required Order actions.
As part of the NRCs ongoing activities to monitor the licensees implementation of the
Order, the inspectors interviewed 10 individuals who had received the training in
November 2007 to determine how effective the training had been in delivering its
message. The inspectors posed four questions to each of the individuals:
(1) What did you take away from the training?
(2) Has it changed your daily work activities?
(3) Do you have any specific examples?
(4) Has the training changed how you interact with your peers?
In addition, to determine whether the licensee was following its Business Practice, the
inspectors reviewed the assessment forms generated when an issue was brought to
FENOCs Regulatory Affairs group for evaluation.
b.
Observations and Findings
Based on the documentation reviews and observations, the inspectors concluded that
the training was effective at instilling within the FirstEnergy management an enhanced
awareness/sensitivity to issues, and the need to ensure that any issues that could
potentially impact Davis-Besse, Perry, or Beaver Valley, are promptly brought to
FENOCs attention. Each of the 10 individuals interviewed indicated that they were
much more sensitive to ensuring all potentially affected organizations or individuals are
aware of issues and ongoing activities with specific emphasis on those issues potentially
affecting the nuclear facilities. Each individual indicated that asking who else needs to
be aware of an issue has become a standard practice in day-to-day activities. While
there were few examples of specific issues actually being brought to the attention of
Regulatory Affairs staff, individuals identified numerous items in which they or others had
raised the question of who else needs to be aware of the issue. All individuals indicated
that it has become an expected practice during peer meeting/interactions to question the
extent to which potentially impacted organizations have been informed of issues.
Issues raised to the Regulatory Affairs organization are appropriately reviewed for
applicability to the nuclear facilities. Further, in a proactive move, Regulatory Affairs has
implemented a practice of attending meetings in which issues that could affect the
nuclear facilities would likely arise.
38
Enclosure
These results are also being documented in inspection reports for Davis-Besse
(05000346/2008004), and Beaver Valley (05000334/2007005 and 05000412/2008004).
No findings of significance were identified.
.3
NRC Temporary Instruction (TI 2515/173) Review of the Implementation of the Industry
Ground Water Protection Voluntary Initiative
a. Inspection Scope
The inspector performed a partial review of station implementation of the industry ground
water protection initiative for Objective 2.2 Voluntary Communication. As part of that
review, the inspector evaluated the licensees response to an on-site leak of buried
piping associated with the ESW system, which started on or about April 25, 2008.
This inspection constituted a partial sample as defined in TI 2515/173.
b. Findings
No findings of significance were identified.
4OA6 Meetings
.1
Exit Meeting
The inspectors presented the inspection results to the Site Vice President,
Mr. Mark Bezilla, and other members of licensee management on October 14, 2008.
The inspectors asked the licensee whether any materials examined during the
inspection should be considered proprietary. No proprietary information was identified.
.2
Interim Exit Meeting
The preliminary results of the licensees radiological environmental monitoring and
radioactive material control programs, and verification of the PI for public radiation safety
with the Plant General Manager, Mr. K. Kruger, was held on September 12, 2008.
4OA7 Licensee-Identified Violations
The following violations of very low safety significance (Green) were identified by the
licensee and are violations of NRC requirements, which meets the criteria of Section VI
of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as NCVs.
Cornerstone: Mitigating Systems
Technical Specification (TS) 3.5.3, Emergency Core Cooling Systems (ECCS) and
Reactor Core Isolation Cooling (RCIC) System, Condition A.1, required that when the
RCIC system is inoperable, it must be verified within one hour, by administrative means,
that HPCS system is operable. Condition B.1 of TS 3.5.3 requires that when the
Required Action and associated Completion Times of Condition A are not met the plant
must be in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Contrary to this requirement, on
December 11, 2007, the HPCS was declared inoperable for maintenance and the plant
39
Enclosure
remained in Mode 1. Specifically, on January 14, 2008, the licensee discovered that the
RCIC flow controller output voltage did not meet operability requirements and this
condition previously existed since December 10, 2007. Not knowing that TS LCO 3.5.3
was not met, licensee personnel did not make the required mode changes. Upon
discovery, the licensee took immediate actions to restore RCIC operability. The finding
was determined to be of very low safety significance because the system inoperable
time was less than 30 days (CR 08-38443).
10 CFR Part 50, Appendix B, Criterion XI, Test Control, requires, in part, that a test
program shall be established to assure that all testing required to demonstrate that
structures, systems, and components will perform satisfactorily in service is identified
and performed in accordance with written test procedures which incorporate the
requirements and acceptable limits contained in applicable design documents. Contrary
to this, on July 21, 2007, the licensee failed to test the C Emergency Service Water
pump discharge valve for seat leakage following valve replacement. This resulted in
high pressure core spray system inoperability and unavailability in May 2008 due to low
keep-fill system pressure. Immediate corrective actions included repair of the affected
valve. The finding was determined to be of very low safety significance because the
system unavailability time was less than three days. (CR 08-40969)
Cornerstone: Occupational Radiation Safety
Perry Plant TS 5.7.1 states in part, that each high radiation area shall be barricaded and
conspicuously posted as a high radiation area. Contrary to the above, on
June 20, 2008, an unlabeled drum of radioactive material with dose rates of 120 millirem
per hour at 30 centimeters was found unattended in the non-high radiation area
controlled area of the control rod drive rebuild room. A violation of regulatory
requirements occurred when the area was not effectively barricaded, controlled, and
conspicuously posted. This was identified in the licensees CAP as CR 08-42154.
Immediate corrective actions were to label and relocate the drum into a properly posted
and controlled high radiation area. The finding was determined to be of very low safety
significance because it was not an as-low-as-is-reasonably-achievable planning issue,
there was no overexposure nor potential for overexposure, and the licensees ability to
assess dose was not compromised.
ATTACHMENT: SUPPLEMENTAL INFORMATION
1
Attachment
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
M. Bezilla, Vice President Nuclear
K. Krueger, Plant General Manager
M. Alfonso, Manager, Chemistry
A. Cayia, Director, Performance Improvement
K. Cimorelli, Director, Maintenance
D. Evans, Manager, Operations
E. Gordon, Radiation Protection Operational Superintendent
J. Grabner, Director, Site Engineering
H. Hanson, Jr., Director, Work and Outage Management
S. Thomas, Manger, Radiation Protection
LIST OF ITEMS OPENED, CLOSED, DISCUSSED
Opened and Closed 05000440/2008004-01
Impaired Fire Barrier for Safety-Related Building (Section
1R05)05000440/2008004-02
Failure to Implement Compensatory Measures for a Risk-
Management Activity (Section 1R13.1)05000440/2008004-03
Failure to Implement a Procedurally-Required Risk
Management Activity for a Protected Train (Section 1R13.2)05000440/2008004-04
Failure to Use Procedures for Work Affecting Safety
(Section 1R15)05000440/2008004-05
Adequacy of Airlock Ball Valve Maintenance (4OA2.3)05000440/2008004-06
Failure to Adequately Manage Risk Associated With
Working Around a Risk-Significant Underground Vault
(Section 4OA3.2)05000440/2008004-07
Loss of Configuration Control of the Hydrogen Water
Chemistry Injection System Resulting in High Radiation
Levels (Section 4OA3.3)
2
Attachment
Closed
05000440/2008-001-00
LER
Condition Prohibited by Technical Specifications Due to
Unrecognized Reactor Core Isolation Cooling Inoperability
(Section 4OA3)
05000440/2008-003-00
LER
Inoperable High Pressure Core Spray System Results in
Loss of Safety Function 05000440/2008003-01
Adequacy of Airlock Ball Valve Maintenance
(Section 4OA3.2)
Discussed 05000440/2007002-02
Procedures Inappropriate to Circumstances for Degraded
Containment Lower Airlock Inner Door Seal System
(Section 4OA2.3)
Temporary Instruction
2515/173
TI
Review of the Implementation of the Industry Ground Water
Protection Voluntary Initiative (Section 4OA5)
3
Attachment
LIST OF DOCUMENTS REVIEWED
The following is a partial list of documents reviewed during the inspection. Inclusion on this list
does not imply that the NRC inspector reviewed the documents in their entirety, but rather that
selected sections or portions of the documents were evaluated as part of the overall inspection
effort. Inclusion of a document on this list does not imply NRC acceptance of the document or
any part of it, unless this is stated in the body of the inspection report.
1R01 Adverse Weather
ONI-ZZZ-1; Tornado or High Winds; Revision 8
IOI-0015; Seasonal Variations; Revision 14
1R04 Equipment Alignment
VLI R-45; Division 3 Diesel Generator Fuel Oil System (Unit 1); Revision 3
VLI R-47; Division 3 Diesel Generator Lube Oil System (Unit 1); Revision 3
SDM E-22B; High Pressure Core Spray Diesel Generator System; Revision 8
GCI-0016; Scaffolding Erection, Modification or Dismantling Guidelines, Revision 14
CR 08-35043; Division 3 Diesel Governor Oil Level; dated February 5, 2008
CR 08-45038; Fire Impairment Not Prepared for Div 3 DG Exhaust Damper Work;
dated 19 August 2008
USAR Section 9.2.1; Emergency Service Water System; Revision 14
System Description Manual (SDM) P45; Emergency Service Water System; Revision 9
SDM P48; Service Water/Emergency Service Water System Chlorination; Revision 4
CR 08-44095; ESW B Pump has Plexiglass Installed Behind Coupling Guard; dated 7/31/08
CR 08-44079; ESW B Pump Discharge Insulation Separated at Pipe and Pump; dated 7/31/08
VLI-P45; Emergency Service Water System; Revision 7
CR 07-12624; NRC Question on Construction Deficiency Tag Found Hanging on 2P42 HX
supports
CR 08-42723; Sodium Hypochlorite Leak in ESW Supply Line in ESW Pumphouse
USAR Section 9.4.6; Revision 14
SDM M14; Containment Vessel and Drywell Purge System; Revision 5
SOI-M14; Containment Vessel and Drywell Purge System; Revision 18
VLI M14; Containment Vessel and Drywell Purge System (Unit 1); Revision 6
Drawing 912-0604; Containment Vessel and Drywell Purge; Revision BB
VLI E22A; High Pressure Core Spray; Revision 7
Engineering Evaluation Request 600491029; Scaffold in ESW Diesel Fire Pump House; dated
September 10, 2008
1R05 Fire Protection (Annual/Quarterly)
FPI-0IB; Intermediate Building; Revision 5
FPI-1AB; Auxiliary Building; Revision 2
FPI-0CC; Control Complex; Revision 7
FPI-A-A02, "Periodic Fire Inspections," Revision 5
PAP-1910, "Fire Protection Program," Revision 15
PAP-0204, "Housekeeping/Cleanliness Control Program," Revision 20
Drawing D-926-002; Emergency Service Water Pumphouse; Revision E
Drawing D-926-001; Emergency Service Water Pumphouse; Revision K
CR-08-44968; NRC ID'd: NRC Identified Door Open Without Fire Impairment; dated 8/18/08
FPI-A-C01; Fire Protection Program Control Processes (Hot Work Permits, Transient
Combustible Permits, Impairment Permits, and Fire Watches); Revision 10
The Operating License
4
Attachment
FPI-1DG, Diesel Generator Building; Revision 5
Perry USAR for Unit 1, Appendix 9A, Fire Protection Evaluation Plan (Section 9A.4.5, Diesel
Generator Building); Revision 12
CR 08-45442; Unplanned Fire Impairment For F-3C Fire Barrier; dated August 27, 2008
CR 08-45405; Unplanned Fire Impairment For CC-323; dated August 27, 2008
1R11 Licensed Operator Requalification Program
OTLC-3058200809_PY-SGC4; July 23, 2008 Scenario Guide; dated July 21, 2008
1R12 Maintenance Effectiveness
CR 08-41083; Failure of HPCS Test Valve To SP To Fully Stroke Open On The First Attempt;
dated May 31, 2008
CR 08-40520; HPCS Discharge Strainer Blowdown Valve Indicating Light Out; dated
May 18, 2008
CR 08-37864; Discrepancies In PTI-M39-P0002, HPCS Pump Room Cooler Performance
Testing; dated April 7, 2009
Perry Nuclear Power Plant - Maintenance Rule Items List
1R13 Maintenance Risk Assessments and Emergent Work Control
Perry Work Implementation Schedule; Week 10, Period 5
Perry Work Implementation Schedule; Week 1, Period 6
Perry Work Implementation Schedule; Week 2, Period 6
Notification 600472744; Tornado External Missiles and Flooding
Engineering Evaluation Request; Notification # 600250251
Engineering Evaluation Request; Notification # 600308906
Engineering Evaluation Request; Notification # 600472744
CR 05-02081; RFA Request Engineering Evaluate Removal Of Floor Plug; dated
March 11, 2005
1R15 Operability Evaluations
CR 08-44299; Failure to Meet Acceptance Criteria of SVI-R42T5214; dated August 5, 2008
Prompt Operability Determination Form; CR 08-44299; dated August 6, 2008
Prompt Operability Determination Form; CR 08-44262; dated August 8, 2008
CR 08-46155; Seal task Freq Exceeds EQ Calc Life For ESW Ventilation Damper Actuators;
dated September 11, 2008
CR 01-4102; 1M32F0040B Damper Shaft Exhibits Undercut Exceeding Code Acceptance
Criteria; dated November 28, 2001
CR 08-46155; Seal Task Frequency Exceeds EQ Calculation for ESW Ventilation Damper
Actuators; dated September 11, 2008
CR 08-46302; Hydramotors Have A Grace Period Longer Than Allowed By Commitment Letter
L00631; dated September 12, 2008
LER 86-021-00; Hydraulic Seal Failures Result In Inoperable Diesel Generator Building
Ventilation Dampers
SDM G33; Reactor Water Clean-up System; Revision 9
SDM E31; Leak Detection System; Revision 8
SDM P41; Service Water System; Revision 9
PAP-0205; Operability of Plant Systems; Revision 18
WO 200272885; Perform SVI-P41-T2001 (92D) Service Water to Cooling Towers Isolation
Valve Operability Test; dated September 22, 2008
CR 08-46484; Rising Trend in Containment Radwaste Sump In Leakage; dated
September 17, 2008
5
Attachment
CR 08-46546; RWCU Delta Flow Rate Met Threshold for Duty Team Phone Call; dated
September 19, 2008
CR 08-46613; RWCU Leakage Identified in the RWCU Heat Exchanger Room; dated
September 19, 2008
CR 08-46680; SW to Cooling Tower Inboard Isolation Valve Failed to Close During
Surveillance; dated September 22, 2008
CR 01-3384; RFA-Retest Requirements (Why Stroke Valves Twice); dated September 20, 2001
CR 08-45326; Incorrect Gaskets Found on ESW Screen Wash Pump; dated August 26, 2008
CR 08-46852; Functionality Assessment Not Requested for Leak in RWCU Piping; dated
September 25, 2008
CR 08-46986; Unsatisfactory Draft Functionality Assessment; dated September 24, 2008
1R19 Post-Maintenance Testing
WO 200329040; Suppression Pool Level A Wet Leg; dated July 14, 2008
Problem Solving Plan; CR 08-43008 Suppression Pool Instruments Read Incorrectly Following
SVI-E51-T11295E; Revision 0
CR 08-42640; Suppression Pool Level Instruments; dated July 1, 2008
CR 08-43008; Suppression Pool Level A Instrument Read Low After Testing Repeat Issue;
dated July 9, 2008
CR 08-42637; A Suppression Pool Instrument Read Lower Following Venting; dated
July 1, 2008
WO 200328695; Troubleshoot Cause of Multiple AEGTS 'A' Low Flow Alarms; dated
July 14, 2008
CR 08-42798; AEGTS Fan A Low Flow Alarms; dated July 3, 2008
CR 06-00267, New Transmitter Installation Results in Gross Fail Operation Deficiency; dated
January 18, 2006
CR 07-30597, Unplanned Tech Spec Entry Due to Hi Gross Fail Locked In; dated
November 27, 2007
CR 08-46223, Received Gross Fail High During Norma Surveillance Flow Testing; dated
September 13, 2008
ICI-B21-1, Rosemount Master Trip Unit (510DU) and (710DU); Revision 5
SVI-E12-T1195-C, LPCI Pump C Low Flow (Bypass) Channel Calibration for 1E12-N052C;
Revisions 5 and 6
SVI-E51-T1293-A, RCIC Actuation - CST Low Level Channel A Calibration for 1E51-N035A;
Revisions 4 and Revision 5
SVI-P41-T2001; Service Water to Cooling Towers Isolation Valve Operability Test; Revision 6
SVI-G43-T1305E; Accident Monitoring Suppression Pool Water Level Channel Calibration;
Revision 3
WO 200340028; Perform Visual Inspections of OP41F0420 MOV Operator Identify Deficiencies,
and Cycle Valve Remotely for Testing; dated September 23, 2008
WO 200203776; Perform Service Water to Cooling Towers Isolation Valve Operability Test SVI
for PMT of Valve P41F0420; dated September 25, 2008
WO 200201001; Perform Recorder Replacements Utilizing ECP 06-0016-01 which superseded
ECP 04-0043 & ECP 06-0069; dated September 23, 2008
ECP 06-0016-001; Replace Recorders 1G43R0093A, 1G43R0073A, 1D23R0250A,
1D23R0180A, 1M51R0090 and 1M51R0091 with New Recorders 1G43R0103A,
1D23R0281A and 1M51R0731; dated January 27, 2008
CR 08-46680; SW to Cooling Tower Inboard Isolation Valve Failed to Close During
Surveillance; dated September 22, 2008
CR 06-01466; Westronics Recorder Series 1220B ECP Problems; dated March 29, 2006
6
Attachment
CA 05-00013; Suppression Pool Level High Range Recorder Blue Pen Failed; dated
January 1, 2005
1R22 Surveillance Testing
WO 200274103; SVI-P42T2001A; Emergency Closed Cooling System A Pump and Valve
Operability; dated August 4, 2008
WO 200314659; Visual Inspection of the Emergency Diesel Generator hallway; dated
August 2008
SOI-E22B, Division 3 Diesel Generator; Revision 23
SVI-E22-T1319, Diesel Generator Start and Load Division 3; Revision 14
SVI-C51-T0030-G, APRM G Channel Calibration for 1C51-K605G; Revision 9
SVI-C51-T0051A; OPRM Channel A Functional For 1C51-K603A; Revision 4
WO 200269152; Perform SVI-C61-T1200 (184D) OPRM Channel A Functional for 1C51-K603A;
dated September 25, 2008
1EP6 Drill Evaluation
OTLC-3058200810-PY-SGC2; dated August 22, 2008
2OS1 Access Control to Radiologically Significant Areas
CR 07-26352; Potential LHRA Issues Associated with the Spent Fuel Clean-Out Project; dated
September 2007
CR 07-26415; Container Identified Tied Off to handrail in Fuel Handling Building; dated
September 2007
CR 07-26726; Locked High Radiation Area Key/Door Controls; dated September 2007
CR 07-26930; Change Management Failed to Identify a Change in VHRA Key (Inventory
Frequency); dated September 2007
CR 08-42154; Elevated Dose Rates on Unlabeled Drum; dated June 2008
HPI-C0010; Radiation Protection Support of Plant Startup; Revision 5
HPI-C0014; Radlock Key Issue; Revision 0
HPI-L0009; Discrete Particle Control; Revision 4
IOI-17; Drywell Entry and Access Control; Revision 10
NOP-WM-7025; High Radiation Area Program; Revision 02
NOP-WM-7003; Radiation Work Permit (RWP); Revision 04
4OA1 Performance Indicator Verification
Perry Safety System Functional Failures; July 2007
Perry Safety System Functional Failures; August 2007
Perry Safety System Functional Failures; September 2007
Perry Safety System Functional Failures; October 2007
Perry Safety System Functional Failures; November 2007
Perry Safety System Functional Failures; December 2007
Perry Safety System Functional Failures; January 2008
Perry Safety System Functional Failures; February 2008
Perry Safety System Functional Failures; March 2008
Perry Safety System Functional Failures; April 2008
Perry Safety System Functional Failures; May 2008
Perry Safety System Functional Failures; June 2008
LER 2007-003; Improper Containment Floor Grating Installation Results in an Unanalyzed
Condition; dated October 26, 2007
NOBP-LP-4012; NRC Performance Indicators; Revisions 3
7
Attachment
SVI-P35-T3011; Perry Operations Manual Surveillance Instruction; Dose Equivalent Iodine
Analysis; Revision 6
4OA2 Identification and Resolution of Problems
WO 200273140; Penetration Pressurization Valve Operability Test; dated March 27, 2008
CR 08-43113; Condition Report 08-41101 Did Not Identify The Airlock Ball Valve Failure Cause;
dated July 11, 2008
CR 08-41097; Upper Air Lock Outer Door Unplanned Tech Spec Entry; dated June 1, 2008
CR 08-41101; P53-Upper Airlock Outer Door Outer Seal; dated June 1, 2008
WO 200176053; Upper Containment Airlock Outer Door Tubing; dated March 29, 2008
WO 200249806; Upper Containment Airlock Outer Door Ball Valve; dated March 29, 2008
WO 200324733; 3-Way Valve Outer Door Small Seal Upper; dated June 4, 2008
WO 200324651; Upper Containment Airlock Outer Door Seal; dated June 2, 2008
CR 08-46177; RWCU Inlet Conductivity Reading Erratic; dated September 12, 2008
CR 08-46160; 1N25-N226B Yarway Pegged High MSR 1B DT Alarm; dated
September 11, 2008
CR 08-40969; High Pressure Core Spray Inoperable; dated May 28, 2008
WO 200272874; HPCS ESW Pump Discharge Check Valve; dated May 31, 2008
WO 200176053; Upper Containment Outer Door; dated March 29, 2008
CR 08-43678; Upper Airlock Order Contains Parts Discrepancy Used In Ball Valve Rebuild;
dated July 23, 2008
CR 08-43422; Near Miss Incident Concerning SAM9; dated July 18, 2008
4OA3 Follow-up of Events and Notices of Enforcement Discretion
CR 08-38443; RCIC Controller Output Computer Point, Decreasing Trend; dated April 16, 2008
CR 08-3911; Unplanned Tech Spec Entry RCIC System Controller Failure; dated April 24, 2008
4OA5 Other Activities
CR 08-39814; ESW Coupling Leak - Division 2; dated May 2008
CR 08-43250; Perry Response to NRC Tritium Inquiry; dated July 2008
FirstEnergy Groundwater Field Sampling Plan, Perry Nuclear Power Plant; dated August 2007
NOP-OP-2012; Groundwater Monitoring; Revisions 01 and 02
8
Attachment
LIST OF ACRONYMS USED
°F
degrees Fahrenheit
alternating current
alternate decay heat removal
annulus exhaust gas treatment system
average power range monitor
Corrective Action Program
CFR
Code of Federal Regulations
CR
condition report
Demand for Information
diesel fire pump
emergency closed cooling
Engineering Evaluation Request
emergency service water
FirstEnergy Nuclear Operating Company
Finding
FPI
Fire Protection Instruction
GMI
Generic Mechanical Instruction
hydrogen water chemistry
IMC
Inspection Manual Chapter
IP
Inspection Procedure
IR
Inspection Report
LCO
limiting condition for operation
LER
Licensee Event Report
low pressure core spray
motor-operated valve
mitigating systems performance index
MegaWatt
non-cited violation
NEI
Nuclear Energy Institute
Nuclear Operating Procedure
NRC
Nuclear Regulatory Commission
oscillating power range monitor
Perry Administrative Procedure
performance indicator
reactor core isolation cooling
Significance Determination Process
SVI
Surveillance Instruction
TI
Temporary Instruction
TS
Technical Specification
Updated Final Safety Analysis Report
Updated Safety Analysis Report
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